UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT PURSUANT

TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 

Date of report (Date of earliest event reported): December 31, 2006

 

 

ENTERPRISE GP HOLDINGS L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware	1-32610	13-4297064
(State or Other Jurisdiction of Incorporation or Organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

1100 Louisiana, 10^th Floor
Houston, Texas 77002
(Address of Principal Executive Offices, including Zip Code)

(713) 381-6500
(Registrant’s Telephone Number, including Area Code:)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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Item 8.01. Other Events.

 

We are filing the audited December 31, 2006 consolidated balance sheet of EPE Holdings, LLC, which is included as Exhibit 99.1 to this Current Report on Form 8-K. EPE Holdings, LLC is the general partner of Enterprise GP Holdings L.P.

Item 9.01. Financial Statements and Exhibits.

 

(d) Exhibits.

 

 

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

 

 

 

 

 

 

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EXHIBIT 23.1

 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

We consent to the incorporation by reference in Registration Statement No. 333-129668 of Enterprise GP Holdings L.P. of our report dated February 28, 2007, relating to the consolidated balance sheet of EPE Holdings, LLC at December 31, 2006, appearing in the Current Report on Form 8-K of Enterprise GP Holdings L.P. dated March 22, 2007.

 

/s/ DELOITTE & TOUCHE LLP

 

Houston, Texas

March 22, 2007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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EXHIBIT 99.1

 

 

 

 

 

 

 

 

EPE HOLDINGS, LLC

 

Consolidated Balance Sheet at December 31, 2006

and Report of Independent Registered Public Accounting Firm

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EPE HOLDINGS, LLC

TABLE OF CONTENTS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors of EPE Holdings, LLC

Houston, Texas

 

We have audited the accompanying consolidated balance sheet of EPE Holdings, LLC (the “Company”) at December 31, 2006. This consolidated financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this consolidated financial statement based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, such consolidated balance sheet presents fairly, in all material respects, the financial position of the Company at December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

 

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 28, 2007

 

 

 

 

 

 

 

 

 

 

 

 

 

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EPE HOLDINGS, LLC

CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2006

(Dollars in thousands)

 

 

 

 

See Notes to Consolidated Balance Sheet

 

 

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EPE HOLDINGS, LLC

NOTES TO CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2006

 

1. Company Organization and Basis of Financial Statement Presentation

 

Significant Relationships Referenced in Notes to Consolidated Balance Sheet

 

Unless the context requires otherwise, references to “we,” “us,” “our” or “EPE Holdings, LLC” are intended to mean and include the business and operations of EPE Holdings, LLC, as well as its consolidated subsidiaries, which include Enterprise GP Holdings L.P. (“ Enterprise GP Holdings”) and its consolidated subsidiaries. Enterprise Products GP LLC, Enterprise Products Partners L.P., and Enterprise Products Operating L.P. and their respective consolidated subsidiaries are consolidated subsidiaries of Enterprise GP Holdings.

 

References to “EPE Holdings” are intended to mean EPE Holdings, LLC, individually, and not on a consolidated basis.

 

References to “Enterprise Products Partners” mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries, which include Enterprise Products Operating L.P. and its consolidated subsidiaries.

 

References to the “Operating Partnership” mean Enterprise Products Operating L.P., and its consolidated subsidiaries. Enterprise Products Operating L.P. is the principal operating subsidiary of Enterprise Products Partners L.P.

 

References to “Enterprise Products GP” mean Enterprise Products GP, LLC, individually as the general partners of Enterprise Products Partners L.P and not on a consolidated basis.      

 

References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the units of which are listed on the New York Stock Exchange (“NYSE”) under ticker symbol “TPP.” References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by a private company subsidiary of EPCO.

 

References to “Employee Partnerships” mean EPE Unit L.P. and EPE Unit II, L.P., collectively, which are private company affiliates of EPCO. References to “EPE Unit I” and “EPE Unit II” refer to EPE Unit L.P. and EPE Unit II, L.P., respectively.

 

References to “EPCO” mean EPCO, Inc., which is a related party affiliate to all of the foregoing named entities.

 

Company Organization and Formation

 

EPE Holdings is a Delaware limited liability company that was formed in April 2005 to become the general partner of Enterprise GP Holdings. EPE Holdings’ business purpose is to manage the affairs and operations of Enterprise GP Holdings. At December 31, 2006, Dan Duncan LLC owned 100% of the membership interests of EPE Holdings.

 

Enterprise GP Holdings is a publicly traded limited partnership that completed an initial public offering of its common units in August 2005 and trades on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPE.” Enterprise GP Holdings’ assets consist of its ownership of Enterprise Products GP and certain limited partner interests in Enterprise Products Partners. At December 31, 2006, Enterprise GP Holdings owned 100% of the membership interests in Enterprise Products GP, which is the general partner of Enterprise Products Partners, and 13,454,498 common units of Enterprise Products Partners. Enterprise GP Holdings has no independent operations outside those of Enterprise Products Partners. Our

 

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general partner interest in Enterprise GP Holdings is fixed without any requirement for capital contributions in connection with additional unit issuances by Enterprise GP Holdings.

 

EPE Holdings, Enterprise GP Holdings, Enterprise Products GP and Enterprise Products Partners are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO.

 

On February 5, 2007, a consolidated subsidiary of Enterprise Products Partners, Duncan Energy Partners L.P. (“Duncan Energy Partners”), completed an initial public offering of its common units (see Note 16). Duncan Energy Partners owns equity interests in certain of Enterprise Products Partners’ midstream energy businesses (see Note 16). The formation of Duncan Energy Partners had no effect on Enterprise Products Partners’ financial statements at December 31, 2006. For financial reporting purposes, Enterprise Products Partners will continue to consolidate the financial statements of Duncan Energy Partners with those of its own (using its historical carrying basis in such entities) and reflect the operations of Duncan Energy Partners in its business segments. The public owners of Duncan Energy Partners’ common units will be presented as a noncontrolling interest in Enterprise Products Partners’ consolidated financial statements beginning in February 2007. The public owners of Duncan Energy Partners have no direct equity interests in the common units of Enterprise Products Partners as a result of this transaction. The borrowings of Duncan Energy Partners will be presented as part of Enterprise Products Partners’ consolidated debt.

 

Basis of Presentation of Consolidated Balance Sheet

 

Since EPE Holdings exercises control over Enterprise GP Holdings, EPE Holdings consolidates its balance sheet with that of Enterprise GP Holdings. EPE Holdings owns a 0.01% general partner interest in Enterprise GP Holdings, which conducts substantially all of EPE Holdings’ business. EPE Holdings has no independent operations and no material assets outside those of Enterprise GP Holdings.

 

The number of reconciling items between our consolidated balance sheet and that of Enterprise GP Holdings are few. The most significant reconciling item is that relating to minority interest in our net assets by the limited partners of Enterprise GP Holdings and the elimination of our investment in Enterprise GP Holdings with our underlying partner’s capital account in Enterprise GP Holdings. See Note 13 for additional details regarding minority interest ownership in our consolidated subsidiaries.

 

Note 2. Summary of Significant Accounting Policies

 

Allowance for Doubtful Accounts

 

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. Our procedure for determining the allowance for doubtful accounts is based on (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts. Our allowance for doubtful accounts was $23.4 million at December 31, 2006.

 

Cash and Cash Equivalents

 

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.

 

 

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Consolidation Policy

 

We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all material intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership.

 

If the investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material and remain on our balance sheet (or those of our equity method investees) in inventory or similar accounts.

 

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

 

Contingencies

 

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Our management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

 

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.

 

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

 

Deferred Revenues

 

We recognize revenues when earned. Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue.

 

Dollar Amounts

 

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

 

Environmental Costs

 

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s estimate of the ultimate cost to remediate a site. Expenditures to mitigate or prevent future environmental contamination are capitalized.

 

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Environmental costs and related accruals were not significant prior to the GulfTerra Merger. As a result of the merger, we assumed an environmental liability for remediation costs associated with mercury gas meters. The balance of this environmental liability was $20.3 million at December 31, 2006. At December 31, 2006, total reserves for environmental liabilities, including those related to the mercury gas meters, were $24.2 million. At December 31, 2006, $7.1 million of this liability is classified as current.

 

Equity Awards

 

In connection with the incentive plans of EPCO and its affiliates, we record amounts related to unit option and restricted unit awards and profits interests. See Note 4.               

 

We currently account for our equity awards using the provisions of SFAS 123(R),“Share-Based Payment.” Prior to January 1, 2006, our equity awards were accounted for using the intrinsic value method described in Accounting Principles Board Opinion (“APB”) 25, “Accounting for Stock Issued to Employees.” SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at grant date. The fair value of an equity award is estimated using option pricing models (Black-Scholes or binomial models). Under SFAS 123(R), the fair value of an award is amortized to earnings on a straight-line basis over the requisite service or vesting period. On January 1, 2006, we reclassified previously recognized deferred compensation related to nonvested awards due to the adoption of SFAS 123(R).

 

Estimates

 

Preparing EPE Holdings’ consolidated financial statements in conformity with generally accepted accounting principles in the United States of America (or “GAAP”) requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

 

Exchange Contracts

 

Exchanges are contractual agreements for the movements of NGLs and certain petrochemical products between parties to satisfy timing and logistical needs of the parties. Net exchange volumes borrowed from us under such agreements are valued and included in accounts receivable, and net exchange volumes loaned to us under such agreements are valued and accrued as a liability in accrued gas payables.

 

Receivables and payables arising from exchange transactions are settled with movements of products rather than with cash. When payment or receipt of monetary consideration is required for product differentials and service costs, such items are recognized in our consolidated financial statements on a net basis.

 

Financial Instruments

 

We use financial instruments such as swaps, forward and other contracts to manage price risks associated with inventories, firm commitments, interest rates, foreign currency and certain anticipated transactions. We recognize these transactions on our balance sheet as assets and liabilities based on the instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. Changes in fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instrument meets the criteria of a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the financial instrument meets the criteria of a cash flow hedge, gains and losses incurred on the instrument are recorded in other comprehensive income. Gains and losses on cash flow hedges are reclassified from other comprehensive income to earnings when the forecasted transaction

 

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occurs or, as appropriate, over the economic life of the underlying asset. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

 

To qualify as a hedge, the item to be hedged must expose us to risk and the related hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at its inception and thereafter on a quarterly basis. Any hedge ineffectiveness is immediately recognized in earnings. See Note 6.

 

Foreign Currency Translation

 

In October 2006, we acquired all of the outstanding stock of an affiliated NGL marketing company located in Canada (see Note 16). Financial statements of this foreign operation are translated into U.S. dollars from the Canadian dollar, its functional currency, using the current rate method. Assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, while revenue and expense items are translated at average rates of exchange during the reporting period. Exchange gains and losses arising from foreign currency translation adjustments are reflected as separate components of accumulated other comprehensive income in the accompanying Consolidated Balance Sheet.

 

We attempt to hedge this currency risk (see Note 6).

 

Impairment Testing for Goodwill

 

Our goodwill amounts are assessed for impairment (i) on a routine annual basis during the second quarter of each year or (ii) when impairment indicators are present. If such indicators occur (e.g., the loss of a significant customer, economic obsolescence of plant assets, etc.), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its book value. If the fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. See Note 11.

 

Impairment Testing for Long-Lived Assets

 

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.

 

Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values in accordance with SFAS 144. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the amount at which an asset or liability could be bought or settled in an arm’s-length transaction. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques.

 

Impairment Testing for Unconsolidated Affiliates

 

We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the investee or long-term negative changes in the investee’s industry. In the event we determine that the loss in value of an investment is other than a temporary decline, we record a charge to earnings to adjust the carrying value of the investment to its estimated fair value.

 

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During 2006, we evaluated our investment in Neptune Pipeline Company, LLC (“Neptune”) for impairment. As a result of this evaluation, we recorded a $7.4 million non-cash impairment charge for the year ended December 31, 2006.

 

Income Taxes

 

Our limited liability company structure is not subject to federal income taxes. As a result, our earnings or losses for federal income tax purposes are included in the tax returns of our member. We are organized as a pass-through entity for federal income tax purposes. As a result, our member is individually responsible for the federal income tax on their allocable share of our taxable income.

 

Income taxes is primarily applicable to our state tax obligations under the Texas State Margin Tax and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie Pipeline Company (“Dixie”), both of which are consolidated subsidiaries of ours. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

 

In May 2006, the State of Texas enacted a new business tax (the “Texas Margin Tax”) that replaced its franchise tax.  In general, legal entities that conduct business in Texas are subject to the Texas Margin Tax.  Limited partnerships, limited liability companies, corporations and limited liability partnerships are examples of the types of entities that are subject to the Texas Margin Tax.  As a result of the change in tax law, our tax status in the State of Texas will change from non-taxable to taxable.  See Note 17.

 

Inventories

 

Inventories primarily consist of NGLs, certain petrochemical products and natural gas volumes that are valued at the lower of average cost or market. We capitalize, as a cost of inventory, shipping and handling charges directly related to volumes we purchase from third parties or take title to in connection with processing or other agreements. As these volumes are sold and delivered out of inventory, the average cost of these products (including freight-in charges that have been capitalized) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 7.

 

Minority Interest

 

Minority interest represents third-party ownership interests in the net assets of our subsidiaries that primarily include the limited partners of Enterprise GP holdings, Enterprise Products Partners and our joint ventures. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party ownership interest in such amounts presented as minority interest.

 

At December 31, 2006, our joint venture subsidiaries were Seminole, Dixie, Tri-States Pipeline LLC (“Tri-States”), Independence Hub, LLC (“Independence Hub”), Wilprise Pipeline Company LLC (“Wilprise”) and Belle Rose NGL Pipeline LLC (“Belle Rose”). We will consolidate the balance sheet of Duncan Energy Partners with that of our own, with minority interest treatment for the units of Duncan Energy Partners owned by unitholders other than us. See Note 13 for additional information regarding minority interest in our consolidated subsidiaries.

 

Natural Gas Imbalances

 

In the natural gas pipeline transportation business, imbalances frequently result from differences in natural gas volumes received from and delivered to our customers. Such differences occur when a customer delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period. We have various fee-based agreements with customers to transport their natural gas through

 

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our pipelines. Our customers retain ownership of their natural gas shipped through our pipelines. As such, our pipeline transportation activities are not intended to create physical volume differences that would result in significant accounting or economic events for either our customers or us during the course of the arrangement.

 

We settle pipeline gas imbalances through either (i) physical delivery of in-kind gas or (ii) in cash. These settlements follow contractual guidelines or common industry practices. As imbalances occur, they may be settled (i) on a monthly basis, (ii) at the end of the agreement or (iii) in accordance with industry practice, including negotiated settlements. Certain of our natural gas pipelines have a regulated tariff rate mechanism requiring customer imbalance settlements each month at current market prices.

 

However, the vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several periods. In some cases, settlements of imbalances built up over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time. For those gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which is representative of the estimated value of the imbalances upon final settlement. Changes in natural gas prices may impact our estimates.

 

At December 31, 2006, our natural gas imbalance receivables, net of allowance for doubtful accounts, was $97.8 million, and is reflected as a component of “Accounts and notes receivable – trade” on our Consolidated Balance Sheet. At December 31, 2006, our imbalance payable was $51.2 million, and is reflected as a component of “Accrued gas payables” on our Consolidated Balance Sheet.

 

Property, Plant and Equipment

 

Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in the results of operations for the respective period. For financial statement purposes, depreciation is recorded based on the estimated useful lives of the related assets primarily using the straight-line method. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. See Note 8.

 

Certain of our plant operations entail periodic planned outages for major maintenance activities. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items. We use the expense-as-incurred method for our planned major maintenance activities.

 

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value (accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. To the extent we do not settle an ARO liability at our recorded amounts, we will incur a gain or loss.

 

Restricted Cash

 

Restricted cash represents amounts held by (i) a brokerage firm in connection with our commodity financial instruments portfolio and physical natural gas purchases made on the NYMEX exchange and (ii) us for the future settlement of current liabilities we assumed in connection with our acquisition of a Canadian affiliate in October 2006.

 

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Note 3. Recent Accounting Developments

 

The following information summarizes recently issued accounting guidance that will or may affect our future financial statements:

 

Emerging Issues Task Force Issue (“EITF”) 06-3

 

EITF 06-3,“How Taxes Collected From Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” requires companies to disclose their policy regarding the presentation of tax receipts on the face of their income statements. This guidance specifically applies to taxes imposed by governmental authorities on revenue-producing transactions between sellers and customers (gross receipts taxes are excluded). We adopted EITF 06-3 on January 1, 2007. As a matter of policy, we have consistently reported such taxes on a net basis.

 

SFAS 155

 

SFAS 155, “Accounting for Certain Hybrid Financial Instruments,” amends SFAS 133, Accounting for Derivative Instruments and Hedging Activities, amends SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and resolves issues addressed in Statement 133 Implementation Issue D1, Application of Statement 133 to Beneficial Interests to Securitized Financial Assets. A hybrid financial instrument is one that embodies both an embedded derivative and a host contract. For certain hybrid financial instruments, SFAS 133 requires an embedded derivative instrument be separated from the host contract and accounted for as a separate derivative instrument. SFAS 155 amends SFAS 133 to provide a fair value measurement alternative for certain hybrid financial instruments that contain an embedded derivative that would otherwise be recognized as a derivative separately from the host contract. For hybrid financial instruments within its scope, SFAS 155 allows the holder of the instrument to make a one-time, irrevocable election to initially and subsequently measure the instrument in its entirety at fair value instead of separately accounting for the embedded derivative and host contract. This guidance was effective January 1, 2007, and our adoption of this guidance had no impact on our financial position.

 

SFAS 157

 

SFAS 157, “Fair Value Measurements,” defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 applies only to fair-value measurements that are already required or permitted by other accounting standards and is expected to increase the consistency of those measurements. The statement emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies will be required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop the measurements, and the effect of certain of the measurements on earnings (or changes in net assets) for the period. SFAS 157 is effective for fiscal years beginning after December 15, 2007 and we will be required to adopt SFAS 157 on January 1, 2008. We do not believe that SFAS 157 will have a material impact on our financial position since we already apply its basic concepts in measuring fair values used to record various transactions such as business combinations and asset acquisitions.

 

SFAS 159

 

SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115,” permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected would be reported in net income. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes the company elects for similar types of assets and liabilities. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact that the adoption of SFAS 159 will have on our financial position.

 

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Financial Accounting Standards Board Interpretation (“FIN”) No. 48

 

In accordance with FIN 48, “Accounting for Uncertainty in Income Taxes,” we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with a more than a 50% chance of being realized upon settlement. We did not recognize any such amounts at December 31, 2006. This guidance is effective January 1, 2007, and our adoption of this guidance is not anticipated to have a material impact on our financial position.

 

Note 4. Accounting for Equity Awards

 

Effective January 1, 2006, we adopted SFAS 123(R) to account for equity awards. Prior to our adoption of SFAS 123(R), we accounted for equity awards using the intrinsic value method described in APB 25. SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at grant date. The fair value of an equity award is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an award is amortized to earnings on a straight-line basis over the requisite service or vesting period.

 

Upon our adoption of SFAS 123(R), we recognized a cumulative effect of change in accounting principle of $1.5 million (a benefit), which is included as a component of minority interest since the limited partners of Enterprise Products Partners were allocated their share of this benefit. The cumulative effect adjustment is based on SFAS 123(R)’s requirement to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards. In addition, previously recognized deferred compensation expense of $14.6 million related to Enterprise Products Partners’ nonvested (or “restricted”) common units was reversed on January 1, 2006.

 

Unit Options

 

Under EPCO’s 1998 Long-Term Incentive Plan (the “1998 Plan”), non-qualified, incentive options to purchase a fixed number of Enterprise Products Partners’ common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. In general, options granted under the 1998 Plan have a vesting period of four years and remain exercisable for ten years from the date of grant.

 

In order to fund its obligations under the 1998 Plan, EPCO may purchase common units at fair value either in the open market or directly from Enterprise Products Partners. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.

 

The fair value of each unit option to purchase Enterprise Products Partners’ common units is estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including expected life of the options, risk-free interest rates, expected distribution yield on Enterprise Products Partners’ common units, and expected unit price volatility of Enterprise Products Partners’ common units. In general, our assumption of expected life of the options represents the period of time that the options are expected to be outstanding based on an analysis of historical option activity. Our selection of the risk-free interest rate is based on published yields for U.S. government securities with comparable terms. The expected distribution yield and unit price volatility is estimated based on several factors, which include an analysis of Enterprise Products Partners’ historical unit price volatility and distribution yield over a period equal to the expected life of the option.

 

 

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The information in the following table presents unit option activity under the 1998 Plan for the periods indicated:

 

 

The total intrinsic value of Enterprise Products Partners’ unit options exercised during the year ended December 31, 2006 was $2.2 million. During the year ended December 31, 2006, we received cash of $5.6 million from the exercise of unit options, and our option-related reimbursements to EPCO were $1.8 million.

 

Restricted Units

 

Under the 1998 Plan, Enterprise Products Partners may issue restricted common units to key employees of EPCO and directors of Enterprise Products GP. The 1998 Plan provides for the issuance of 3,000,000 restricted common units of Enterprise Products Partners, of which 1,900,443 remain authorized for issuance at December 31, 2006.

 

In general, restricted unit awards allow recipients to acquire the underlying common units at no cost to the recipient once a defined vesting period expires, subject to certain forfeiture provisions. The restrictions on such units generally lapse four years from the date of grant. The fair value of restricted units is based on the market price of the underlying common units on the date of grant and an allowance for estimated forfeitures.

 

The following table summarizes information regarding Enterprise Products Partners’ restricted units for the periods indicated:

 

 

 

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The total fair value of Enterprise Products Partners’ restricted units that vested during the year ended December 31, 2006 was $1.1 million.

 

Employee Partnerships

 

EPE Unit I. In connection with Enterprise GP Holdings initial public offering in August 2005, EPE Unit I was formed to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in EPE Unit I. In August 2005, EPE Unit I used $51.0 million in contributions it received from its Class A limited partner (an affiliate of EPCO) to purchase 1,821,428 units of Enterprise GP Holdings. Certain EPCO employees, including all of Enterprise Products GP’s executive officers other than Dan L. Duncan and Dr. Ralph S. Cunningham, were admitted as Class B limited partners of EPE Unit I without any capital contributions.

 

Unless otherwise agreed to by EPCO, the Class A limited partner and a majority of the Class B limited partners, EPE Unit I will be liquidated upon the earlier of (i) August 2010 or (ii) a change in control of us or Enterprise GP Holdings. Upon liquidation of EPE Unit I, units having a fair market value equal to the Class A limited partner’s capital base, plus any Class A preferred return for the quarter in which liquidation occurs, will be distributed to the Class A limited partner. Any remaining units will be distributed to the Class B limited partners as a residual profits interest award in EPE Unit I.

 

Prior to our adoption of SFAS 123(R) in January 2006, the estimated value of the profits interest awards was accounted for in a manner similar to a stock appreciation right. Upon our adoption of SFAS 123(R), we began recognizing compensation expense based upon an estimated grant date fair value of the Class B partnership equity awards of approximately $12.6 million.

 

The grant date fair value of the Class B limited partnership equity awards in EPE Unit I was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards ranging from four to five years, (ii) risk-free interest rates ranging from 4.0% to 4.8%, (iii) an expected distribution yield on units of Enterprise GP Holdings ranging from 3.0% to 3.7%, and (iv) an expected unit price volatility for Enterprise GP Holdings’ units ranging from 21.1% to 30.0%.

 

EPE Unit II, L.P. In December 2006, EPE Unit II, L.P. (“EPE Unit II”) was formed to serve as an incentive arrangement for Dr. Ralph S. Cunningham, an executive officer of Enterprise Products GP. The officer, who is not a participant in EPE Unit I, was granted a “profits interest” award in EPE Unit II. EPCO serves as the general partner of EPE Unit II.

 

At inception, EPE Unit II used $1.5 million in contributions it received from an affiliate of EPCO (which was admitted as the Class A limited partner of EPE Unit II as a result of such contribution) to purchase 40,725 units of Enterprise GP Holdings at an average price of $36.91 per unit in December 2006. The officer was issued a Class B limited partner interest in EPE Unit II without any capital contribution.

 

Unless otherwise agreed upon by EPCO, the Class A limited partner and the Class B limited partner, EPE Unit II will be liquidated upon the earlier of (i) December 2011 or (ii) a change in control of us or Enterprise GP Holdings. Upon liquidation of the EPE Unit II, units having a fair market value equal to the Class A limited partner’s capital base will be distributed to the Class A limited partner, plus any Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partner as a residual profits interest award in EPE Unit II.

 

The fair value of the Class B limited partnership equity award in EPE Unit II was estimated on the date of grant using the Black-Scholes option pricing model, which incorporated various assumptions including (i) an expected life of the award of five years, (ii) risk-free interest rate of 4.4%, (iii) an expected distribution yield on units of Enterprise GP Holdings of 3.8%, and (iv) an expected unit price volatility for Enterprise GP Holdings’ units of 18.7%.

 

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Enterprise GP Holdings’ Long-Term Incentive Plan

 

In November 2005, Enterprise GP Holdings filed a registration statement covering the potential future issuance of up to 250,000 of its units in connection with a long-term incentive plan of EPCO (the “2005 Plan”). The 2005 Plan was established to encourage directors of us and employees of EPCO that perform services for Enterprise GP Holdings to increase their ownership of Enterprise GP Holdings units and to develop a sense of proprietorship and personal involvement in the business and financial success of Enterprise GP Holdings. The 2005 Plan provides for the future issuance of unit options, restricted units, phantom units and unit appreciation rights (“UARs”) of Enterprise GP Holdings (limited to 250,000 units).

 

In August 2006, the three of EPE Holdings’ independent directors were issued 10,000 UARs each, for a total of 30,000 UARs. These UARs entitle the directors to receive an amount in the future equal to the excess, if any, of the fair market value of Enterprise GP Holdings units (determined as of the future vesting date) over the grant date price of $35.71 per unit, in units or cash (at the discretion of EPE Holdings). The grant date price of $35.71 per unit differs from the $35.40 per unit closing unit price of Enterprise GP Holdings units on August 3, 2006. The higher grant date price was determined by reference to the closing price of Enterprise GP Holdings units on May 2, 2006, which was the original date that these awards were contemplated to be issued. Each unit appreciation right vests in August 2011. We account for these awards as liabilities due to its current intent to settle these awards in cash. The aggregate fair value of the August 2006 UARs issued to our independent directors was $180 thousand at December 31, 2006.

 

In November 2006, three of EPE Holdings’ independent directors were issued an additional 20,000 UARs and a fourth director was issued 30,000 UARs. The grant date price of these rights was $34.10 per unit. These awards vest in November 2011. The aggregate fair value of the November 2006 UARs was $607 thousand at December 31, 2006. Like the August 2006 UAR awards, we intend to satisfy these awards with cash.

 

 

Other

 

The independent directors of Enterprise Products GP have been granted UARs in the form of letter agreements with each of the directors. These awards are not part of any established long-term incentive plan of EPCO, Enterprise GP Holdings or Enterprise Products Partners. The awards are based upon an incentive plan of EPE Holdings and are made in the form of UAR grants for non-employee directors of Enterprise Products GP. These UARs entitle the directors to receive a cash amount in the future equal to the excess, if any, of the fair market value of the parent company’s units (determined as of a future vesting date) over the grant date price. If the director resigns prior to vesting, his UAR awards are forfeited.

 

In August 2006, three independent directors of Enterprise Products GP were each granted 10,000 UARs, for a total of 30,000 UARs, of which 20,000 were subsequently forfeited due to resignations. The grant date price of the August 2006 UARs was $35.71 per unit. This price differs from the $35.40 per unit closing unit price of Enterprise GP Holdings units on August 3, 2006. The higher grant date price was determined by reference to the closing price of Enterprise GP Holdings units on May 2, 2006, which was the original date that these awards were contemplated to be issued. The remaining 10,000 UARs vest in August 2011. The aggregate fair value of the August 2006 letter agreement UARs was $60 thousand at December 31, 2006.

 

In November 2006, an additional 80,000 UARs were issued under these letter agreements. The grant date price of these rights was $34.10 per unit. The aggregate fair value of the November 2006 letter agreement UARs was $539 thousand at December 31, 2006.

 

These UARs are accounted for as liability awards under SFAS 123(R) since they will be settled with cash.

 

 

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Note 5. Employee Benefit Plans

 

During the first quarter of 2005, we acquired a controlling ownership interest in Dixie, which resulted in it becoming a consolidated subsidiary of ours. Dixie employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in a defined contribution plan and pension and postretirement benefit plans. Due to the immaterial nature of Dixie’s employee benefit plans to our consolidated financial position, our discussion is limited to the following:

 

Defined Contribution Plan

 

Dixie contributed $0.3 million to its company-sponsored defined contribution plan during 2006.

 

Pension and Postretirement Benefit Plans

 

Dixie’s pension plan is a noncontributory defined benefit plan that provides for the payment of benefits to retirees based on their age at retirement, years of service and average compensation. Dixie’s postretirement benefit plan also provides medical and life insurance to retired employees. The medical plan is contributory and the life insurance plan is noncontributory. Dixie employees hired after July 1, 2004 are not eligible for pension and other benefit plans after retirement.

 

The following table presents Dixie’s benefit obligations, fair value of plan assets, unfunded liabilities and accrued benefit liabilities at December 31, 2006.

 

 

Projected benefit obligations and net periodic benefit costs are based on actuarial estimates and assumptions. The weighted-average actuarial assumptions used in determining the projected benefit obligation at December 31, 2006 were as follows: discount rate of 5.75%, expected long-term rate of return on assets of 7.00%; rate of compensation increase of 4.00%; and a medical trend rate of 9.00% for 2007 grading to an ultimate trend of 5.00% for 2010 and later years. Dixie’s net pension and postretirement benefit costs for 2006 were $0.7 million and $0.3 million, respectively.

 

Future benefits expected to be paid from Dixie’s pension and postretirement plans are as follows for the periods indicated:

 

 

On December 31, 2006, Dixie adopted the recognition and disclosure provisions of SFAS 158. SFAS 158 require Dixie to recognize the funded status of its defined benefit pension and other postretirement plans as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income.

 

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The incremental effects of Dixie’s implementation of SFAS 158 on our Consolidated Balance Sheet at December 31, 2006 are presented in the following table. Had we not been required to adopt SFAS 158 at December 31, 2006, we would have recognized an additional minimum liability pursuant to the provisions of SFAS 87.

 

 

Included in Accumulated Other Comprehensive Income (“AOCI”) on the Consolidated Balance Sheet at December 31, 2006 are the following amounts that have not been recognized in net periodic pension costs: unrecognized transition obligation of $1.2 million ($0.7 million, net of tax), unrecognized prior service costs of $1.5 million ($0.9 million, net of tax) and unrecognized actuarial loss of $3.1 million ($1.9 million, net of tax).

 

Note 6. Financial Instruments

 

We are exposed to financial market risks, including changes in commodity prices and interest rates. In addition, we are exposed to fluctuations in exchange rates between the U.S. dollar and Canadian dollar with respect to a recently acquired NGL marketing business located in Canada. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to (i) variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

 

We recognize financial instruments as assets and liabilities on our Consolidated Balance Sheet based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.

 

Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings.

 

To qualify as a hedge, the transaction to be hedged must be exposed to commodity, interest rate or exchange rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.

 

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We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific exposure. When this occurs, we may enter into a new financial instrument to reestablish the economic hedge to which the closed instrument relates.

 

Interest Rate Risk Hedging Program

 

Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements. We assess cash flow risk related to interest rates by (i) identifying and measuring changes in our interest rate exposures that may impact future cash flows and (ii) evaluating hedging opportunities to manage these risks. We use analytical techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis models to forecast the expected impact of changes in interest rates on our future cash flows. Enterprise Products GP oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.

 

We manage a portion of our interest rate exposure by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. We believe it is prudent to maintain an appropriate balance of variable rate and fixed rate debt in the current business environment.

 

Fair Value Hedges – Interest Rate Swaps. As summarized in the following table, we had eleven interest rate swap agreements outstanding at December 31, 2006 that were accounted for as fair value hedges.

 

                

We have designated these interest rate swaps as fair value hedges under SFAS 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in the fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.

 

These eleven agreements have a combined notional amount of $1.1 billion and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on the six-month London interbank offered rate (“LIBOR”) (plus an applicable margin as defined in each swap agreement), and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.

 

The total fair value of these eleven interest rate swaps at December 31, 2006, was a liability of $29.1 million, with an offsetting decrease in the fair value of the underlying debt.

 

Cash Flow Hedges – Forward-Starting Interest Rate Swaps. During the first nine months of 2004, we entered into eight forward starting interest rate swaps having an aggregate notional value of $2.0 billion in anticipation of our financing activities associated with closing the GulfTerra Merger. Our purpose in entering into these financial instruments was to effectively hedge the underlying U.S. treasury rate related to our issuance of $2.0 billion in principal amount of fixed-rate debt. In October 2004, the Operating

 

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Partnership issued $2.0 billion of private placement debt under Senior Notes E through H. Each of the forward starting swaps was designated as a cash flow hedge under SFAS 133.

 

In April 2004, we elected to terminate the initial four forward starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. In September 2004, we settled the remaining four swaps resulting in an $85.1 million payment to the counterparties.

 

The following table presents the notional amount covered by each forward starting swap and the cash gain (loss) associated with each swap upon settlement:

 

The net gain of $19.4 million from these settlements will be reclassified from AOCI to reduce interest expense over the life of the associated debt. We reclassified $4.2 million from AOCI during the year ended December 31, 2006, which reduced the amount of interest expense we recognized.

 

Commodity Risk Hedging Program

 

The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risks associated with such products, we may enter into commodity financial instruments.

 

The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) the value of NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas, NGLs or certain petrochemical products. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

 

We have adopted a policy to govern our use of commodity financial instruments to manage the risks of our natural gas and NGL businesses. The objective of this policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by Enterprise Products GP. We may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months. Enterprise Products GP oversees the strategies associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.

 

At December 31, 2006, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of economic hedges. The fair value of our commodity financial instrument portfolio at December 31, 2006 was a liability of $3.2 million.

 

Foreign Currency Hedging Program

 

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In October 2006, we acquired all of the outstanding stock of an affiliated NGL marketing company located in Canada from EPCO and Dan L. Duncan. Since this foreign subsidiary’s functional currency is the Canadian dollar, we could be adversely affected by fluctuations in foreign currency exchange rates. We attempt to hedge this risk using foreign purchase contracts to fix the exchange rate. As of December 31, 2006, we had entered into foreign purchase contracts valued at $5.1 million, all of which settled in January 2007. In January and February 2007, we entered into $3.8 million and $4.8 million, respectively, of such instruments. These contracts typically settle in the month following their inception. Due to the limited duration of these contracts, we utilize mark-to-market accounting for these transactions.

 

Fair Value Information

 

Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair values due to their short-term nature. The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates. The fair values associated with our interest rate and commodity hedging portfolios were developed using available market information and appropriate valuation techniques.

 

The following table presents the estimated fair values of our financial instruments at December 31, 2006:

 

 

 

Note 7. Inventories

 

 

 

Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs, and certain petrochemical products that are available-for-sale or used by us in the provision of services. Our forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts. Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs. We value our inventories at the lower of average cost or market.

 

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In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties), these volumes are valued at market-related prices during the month in which they are acquired. We capitalize as a component of inventory those ancillary costs (e.g. freight-in and other handling and processing charges) incurred in connection with volumes obtained through such contracts.

 

Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value.

 

Note 8. Property, Plant and Equipment

 

Our property, plant and equipment values and accumulated depreciation balances were as follows at December 31, 2006:

 

 

We capitalized $55.7 million of interest in connection with capital projects during the year ended December 31, 2006.

 

Purchase of Pioneer Plant from TEPPCO. In March 2006, we paid $38.2 million to TEPPCO for its Pioneer natural gas processing plant located in Opal, Wyoming and certain natural gas processing rights related to production from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. After completing this asset purchase, we increased the capacity of the Pioneer natural gas processing plant at an additional cost of $21.0 million. This expansion was completed in July 2006 and enables us to process natural gas production from the Jonah and Pinedale fields that will be transported to

 

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our Wyoming facilities as a result of the contract rights we acquired from TEPPCO. Of the $38.2 million we paid TEPPCO to acquire the Pioneer facility, $37.8 million was allocated to the contract rights we acquired (see Note 11).

 

Purchase of Houston-area pipelines from TEPPCO. In October 2006, we purchased certain idle pipeline assets in the Houston, Texas area from TEPPCO for $11.7 million in cash. These purchases are part of the pipeline projects we announced in July 2006 in connection with our new long-term natural gas transportation and storage contracts with CenterPoint Energy Resources Corp. The acquired pipelines will be modified for natural gas service.

 

Purchase of NGL pipeline from ExxonMobil. In August 2006, we acquired a 220-mile pipeline from ExxonMobil Pipeline Company (“ExxonMobil”) for $97.7 million in cash. This pipeline originates in Corpus Christi, Texas and extends to Pasadena, Texas. This pipeline is a component of the DEP South Texas NGL Pipeline System, which connects our Armstrong and Shoup NGL fractionation facilities located in South Texas to our Mont Belvieu facility.

 

See Note 16 for information regarding our relationship with TEPPCO.

 

Asset retirement obligations

 

We have recorded asset retirement obligations related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. In general, our asset retirement obligations primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities. In addition, our asset retirement obligations may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.

 

Previously, we recorded asset retirement obligations associated with the future retirement and removal activities of certain offshore assets located in the Gulf of Mexico. In December 2005, we adopted FIN 47 and recorded an additional $10.1 million in connection with conditional asset retirement obligations. None of our assets are legally restricted for purposes of settling asset retirement obligations.

 

The following table presents information regarding our asset retirement obligations since December 31, 2005.

 

 

Property, plant and equipment at December 31, 2006 include $3.0 million of asset retirement costs capitalized as an increase in the associated long-lived asset.

 

Certain of our unconsolidated affiliates have AROs recorded at December 31, 2006 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our financial statements.

 

 

 

 

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Note 9. Investments In and Advances To Unconsolidated Affiliates

 

We own interests in a number of related businesses that are accounted for using the equity method of accounting. Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate. See Note 15 for a general discussion of our business segments. The following table shows our investments in and advances to unconsolidated affiliates at December 31, 2006.

                

 

On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates. At December 31, 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost amounts totaling $38.7 million, all of which were attributable to the fair value of the underlying tangible assets of these entities exceeding their book carrying values at the time of our acquisition of interests in these entities.

 

NGL Pipelines & Services

 

At December 31, 2006, our NGL Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

 

VESCO. We own a 13.1% interest in VESCO, which owns a natural gas processing facility and related assets located in south Louisiana.

 

Promix. We own a 50.0% interest in Promix, which owns an NGL fractionation facility and related storage and pipeline assets located in south Louisiana.

 

BRF. We own an approximate 32.3% interest in BRF, which owns an NGL fractionation facility located in south Louisiana.

 

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The combined balance sheet information at December 31, 2006 of this segment’s current unconsolidated affiliates is summarized below.

 

 

Onshore Natural Gas Pipelines & Services

 

At December 31, 2006, our Onshore Natural Gas Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

 

Evangeline. We own an approximate 49.5% aggregate interest in Evangeline, which owns a natural gas pipeline located in south Louisiana. A subsidiary of Acadian Gas, LLC owns the Evangeline interests, which were contributed to Duncan Energy Partners in February 2007 in connection with its initial public offering (see Note 16).

 

Jonah. At December 31, 2006, we owned an approximate 14.4% interest in Jonah, which owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming. Upon completion of the Jonah Phase V expansion project in 2007, we expect to own an approximate 20% equity interest in Jonah, with TEPPCO owning the remaining 80%. Our equity interest in Jonah at December 31, 2006 is based on capital contributions we made to Jonah in connection with its Phase V expansion project through this date. See Note 15 for additional information regarding our Jonah affiliate.

 

The combined balance sheet information at December 31, 2006 of this segment’s current unconsolidated affiliates is summarized below.

 

 

Offshore Pipelines & Services

 

At December 31, 2006, our Offshore Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

 

Poseidon. We own a 36.0% interest in Poseidon, which owns a crude oil pipeline that gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana.

 

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Cameron Highway. We own a 50.0% interest in Cameron Highway, which owns a crude oil pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas. The Cameron Highway Oil Pipeline commenced operations during the first quarter of 2005.

 

Deepwater Gateway. We own a 50.0% interest in Deepwater Gateway, which owns the Marco Polo platform located in the Gulf of Mexico. The Marco Polo platform processes crude oil and natural gas production from the Marco Polo, K2, K2 North and Ghengis Khan fields located in the South Green Canyon area of the Gulf of Mexico.

 

Neptune. We own a 25.7% interest in Neptune, which owns the Manta Ray Offshore Gathering and Nautilus Systems, which are natural gas pipelines located in the Gulf of Mexico.

 

Nemo. We own a 33.9% interest in Nemo, which owns the Nemo Gathering System, which is a natural gas pipeline located in the Gulf of Mexico.

 

The combined balance sheet information at December 31, 2006 of this segment’s current unconsolidated affiliates is summarized below.

 

 

 

Neptune owns the Manta Ray Offshore Gathering System (“Manta Ray”) and Nautilus Pipeline System (“Nautilus”). Manta Ray gathers natural gas originating from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico to numerous downstream pipelines, including the Nautilus pipeline. Nautilus connects our Manta Ray pipeline to our Neptune natural gas processing plant located in south Louisiana. Due to a recent decrease in throughput volumes on the Manta Ray and Nautilus pipelines, we evaluated our 25.7% investment in Neptune for impairment during the third quarter of 2006. The decrease in throughput volumes is primarily due to underperformance of certain fields, natural depletion and hurricane-related delays in starting new production. These factors contributed to significant delays in throughput volumes Neptune expects to receive. As a result, Neptune has experienced operating losses in recent periods.

 

At December 31, 2005, the carrying value of our investment in Neptune was $68.1 million, which included $10.9 million of excess cost related to its original acquisition in 2001. Our review of Neptune’s estimated cash flows during the third quarter of 2006 indicated that the carrying value of our investment exceeded its fair value, which resulted in a non-cash impairment charge of $7.4 million. After recording this impairment charge, the carrying value of our investment in Neptune at December 31, 2006 was $58.8 million.

 

Our investment in Neptune was written down to fair value, which management estimated using recognized business valuation techniques. The fair value analysis is based upon management’s expectation of future cash flows, which incorporates certain industry information and assumptions made by management. For example, the review of Neptune included management estimates regarding natural gas reserves of producers served by Neptune. If the assumptions underlying our fair value analysis change and expected cash flows are reduced, additional impairment charges may result in the future.

 

 

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Petrochemical Services

 

At December 31, 2006, our Petrochemical Services segment included the following unconsolidated affiliates accounted for using the equity method:

 

BRPC. We own a 30.0% interest in BRPC, which owns a propylene fractionation facility located in south Louisiana.

 

La Porte. We own an aggregate 50.0% interest in La Porte, which owns a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas.

 

The combined balance sheet information at December 31, 2006 of this segment’s current unconsolidated affiliates is summarized below.

 

 

 

Note 10. Business Combinations

 

Transactions Completed during the Year Ended December 31, 2006

 

Our expenditures for business combinations during the year ended December 31, 2006 were $276.5 million.

 

Encinal Acquisition. On July 1, 2006, we acquired the Encinal and Canales natural gas gathering systems and related gathering and processing contracts that comprised the South Texas natural gas transportation and processing business of an affiliate of Lewis Energy Group, L.P. (“Lewis”). The aggregate value of total consideration paid or issued to complete this business combination (referred to as the “Encinal acquisition”) was $326.3 million, which consisted of $145.2 million in cash and 7,115,844 common units of Enterprise Products Partners.

 

The Encinal and Canales gathering systems are located in South Texas and are connected to over 1,450 natural gas wells producing from the Olmos and Wilcox formations. The Encinal system consists of 452 miles of pipeline, which is comprised of 280 miles of pipeline we acquired from Lewis in this transaction and 172 miles of pipeline that we own and had previously leased to Lewis. The Canales gathering system is comprised of 32 miles of pipeline. Currently, natural gas volumes gathered by the Encinal and Canales systems are transported by our existing Texas Intrastate System and are processed by our South Texas natural gas processing plants.

 

The Encinal and Canales gathering systems will be supported by a life of reserves gathering and processing dedication by Lewis related to its natural gas production from the Olmos formation. In addition, we entered into a 10-year agreement with Lewis for the transportation of natural gas treated at its proposed Big Reef facility. The Big Reef facility will treat natural gas from the southern portion of the Edwards Trend in South Texas. We also entered into a 10-year agreement with Lewis for the gathering and processing of rich gas it produces from below the Olmos formation.

 

 

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The total consideration paid or granted to Lewis in connection with the Encinal acquisition is as follows:

 

 

In accordance with purchase accounting, the value of Enterprise Products Partners’ common units issued to Lewis was based on the average closing price of such units immediately prior to and after the transaction was announced on July 12, 2006. For purposes of this calculation, the average closing price was $25.45 per unit.

 

Piceance Creek Acquisition. On December 27, 2006, one of our affiliates, Enterprise Gas Processing, LLC, purchased a 100% interest in Piceance Creek Pipeline, LLC (“Piceance Creek”), for cash consideration of $100.0 million. Piceance Creek was wholly owned by EnCana Oil & Gas (“EnCana”).

 

The assets of Piceance Creek consist of a recently constructed 48-mile, natural gas gathering pipeline, the Piceance Creek Gathering System, located in the Piceance Basin of northwestern Colorado. The Piceance Creek Gathering System has a transportation capacity of 1.6 billion cubic feet per day (“Bcf/d”) of natural gas and extends from a connection with EnCana’s Great Divide Gathering System located near Parachute, Colorado, northward through the heart of the Piceance Basin to our 1.5 Bcf/d Meeker natural gas treating and processing complex, which is currently under construction. Connectivity to EnCana’s Great Divide Gathering System will provide the Piceance Creek Gathering System with access to production from the southern portion of the Piceance basin, including production from EnCana’s Mamm Creek field. The Piceance Creek Gathering System was placed in service in January 2007 and began transporting initial volumes of approximately 300 million cubic feet per day (“MMcf/d”) of natural gas. We expect natural gas transportation volumes to increase to approximately 625 MMcf/d by the end of 2007, with a significant portion of these volumes being produced by EnCana, one of the largest natural gas producers in the region. In conjunction with our acquisition of Piceance Creek, EnCana signed a long-term, fixed fee gathering agreement with us and dedicated significant production to the Piceance Creek Gathering System for the life of the associated lease holdings.

 

Our preliminary allocation of this acquisition’s purchase price was as follows: (i) $91.5 million allocated to property, plant and equipment and (ii) $8.5 million to identifiable intangible assets. See Note 11 for additional information regarding the Piceance Creek intangible assets. Since this transaction closed at year-end, our preliminary purchase price allocation is based on estimates and is subject to change when actual values are determined.

 

Other Transactions. In addition to the Encinal and Piceance Creek acquisitions, our business combinations during 2006 included the purchase of (i) an additional 8.2% ownership interest in Dixie for $12.9 million, (ii) all capital stock of an affiliated NGL marketing company located in Canada from related parties for $17.7 million (see Note 16) and (iii) a storage business in Flagstaff, Arizona for $0.7 million.

 

 

 

 

 

 

 

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Purchase Price Allocation for 2006 Transactions

 

Our 2006 business combinations were accounted for using the purchase method of accounting and, accordingly, their cost has been allocated to assets acquired and liabilities assumed based on estimated preliminary fair values. Such preliminary values have been developed using recognized business valuation techniques and are subject to change pending a final valuation analysis. We expect to finalize the purchase price allocations for these transactions during 2007.

 

 

Of the $326.3 million in consideration we paid or granted to effect the Encinal acquisition, $95.2 million has been assigned to goodwill. Management attributes this goodwill to potential future benefits we expect to realize from our other South Texas processing and NGL businesses as a result of the Encinal acquisition. Specifically, the long-term dedication rights we acquired in connection with the Encinal acquisition are expected to improve earnings from our South Texas processing facilities and related NGL businesses due to increased volumes. See Note 11, for additional information regarding our intangible assets and goodwill.

 

 

 

 

 

 

 

 

 

 

 

 

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Note 11. Intangible Assets and Goodwill

 

Identifiable Intangible Assets

 

The following table summarizes our intangible assets at December 31, 2006:

 

 

In general, our intangible assets fall within two categories – contract-based intangible assets and customer relationships. Contract-based intangible assets represent commercial rights we acquired in connection with business combinations or asset purchases. Customer relationship intangible assets represent customer bases that we acquired in connection with business combinations and asset purchases. The values assigned to intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits of associated resource bases are estimated to be consumed or otherwise used, as appropriate.

 

We acquired $141.3 million of intangible assets during the year ended December 31, 2006, primarily attributable to customer relationships we acquired in connection with the Encinal acquisition.

 

The $132.9 million of intangible assets we acquired in connection with the Encinal acquisition (see Note 10) represents the value we assigned to customer relationships, particularly the long-term relationship we now have with Lewis through natural gas processing and gathering arrangements. We recorded $127.1 million in our NGL Pipelines & Services segment associated with processing arrangements and $5.8 million in our Onshore Natural Gas Pipelines & Services segment associated with gathering arrangements. These intangible assets will be amortized to earnings over a 20-year life using methods that closely resemble the pattern in which we estimate the depletion of the underlying natural gas resources to occur.

 

We acquired numerous customer relationship and contract-based intangible assets in connection with the GulfTerra Merger. The customer relationship intangible assets represent the exploration and production, natural gas processing and NGL fractionation customer bases served by GulfTerra and the South Texas midstream assets at the time the merger was completed. The contract-based intangible assets

 

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represent the rights we acquired in connection with discrete contracts to provide storage services for natural gas and NGLs that GulfTerra had entered into prior to the merger.

 

The value we assigned to these customer relationships is being amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Our estimate of the useful life of each resource base is based on a number of factors, including third-party reserve estimates, the economic viability of production and exploration activities and other industry factors. This group of intangible assets primarily consists of the (i) Offshore Pipelines & Platforms customer relationships; (ii) San Juan Gathering System customer relationships; (iii) Texas Intrastate pipeline customer relationships; and (iv) STMA and GulfTerra NGL Business customer relationships.

 

The contract-based intangible assets we acquired in connection with the GulfTerra Merger are being amortized over the estimated useful life (or term) of each agreement, which we estimate to range from two to eighteen years. This group of intangible assets consists of the (i) Petal and Hattiesburg natural gas storage contracts and (ii) Markham NGL storage contracts.

 

The Shell Processing Agreement grants us the right to process Shell’s (or its assignee’s) current and future production within the state and federal waters of the Gulf of Mexico. We acquired this intangible asset in connection with our 1999 purchase of certain of Shell’s midstream energy assets located along the Gulf Coast. The value of the Shell Processing Agreement is being amortized on a straight-line basis over the remainder of its initial 20-year contract term through 2019.

 

Goodwill

 

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; however, it is subject to annual impairment testing. The following table summarizes our goodwill amounts by segment at December 31, 2006.

 

 

Goodwill recorded in connection with the GulfTerra Merger can be attributed to our belief (at the time the merger was consummated) that the combined partnerships would benefit from the strategic location of each partnership’s assets and the industry relationships that each possessed. In addition, we expected that various operating synergies could develop (such as reduced general and administrative costs and interest savings) that would result in improved financial results for the merged entity. Based on miles of pipelines, GulfTerra was one of the largest natural gas gathering and transportation companies in the United States, serving producers in the central and western Gulf of Mexico and onshore in Texas and New Mexico. These regions offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other midstream energy infrastructure.

 

In 2006, the only significant change in goodwill was the recording of $95.2 million in connection with our preliminary purchase price allocation for the Encinal acquisition. Management attributes this goodwill to potential future benefits we may realize from our other south Texas processing and NGL

 

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businesses as a result of acquiring the Encinal business. Specifically, our acquisition of the long-term dedication rights associated with the Encinal business is expected to add value to our south Texas processing facilities and related NGL businesses due to increased volumes. The Encinal goodwill is recorded as part of the NGL Pipelines & Services business segment due to management’s belief that such future benefits will accrue to businesses classified within this segment.

 

The remainder of our goodwill amounts are associated with prior acquisitions, principally that of our purchase of a propylene fractionation business in February 2002 and our acquisition of indirect ownership interests in the Indian Springs natural gas gathering and processing business in January 2005.

 

Note 12. Debt Obligations

 

Our consolidated debt obligations consisted of the following at December 31, 2006:

 

 

Enterprise GP Holdings debt obligation

 

$200 Million Credit Facility. In January 2006, Enterprise GP Holdings amended and restated its $525.0 Million Credit Facility to reflect a new borrowing capacity of $200.0 million, which includes a sublimit of $25.0 million for letters of credit. Amounts borrowed under the new $200.0 Million Credit Facility are due in January 2009. Enterprise GP Holdings has secured its borrowings under this credit

 

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agreement by a pledge of its limited and general partner ownership interests in Enterprise Products Partners.

 

Amounts borrowed under this credit agreement bear interest at a variable interest rate selected by Enterprise GP Holdings at the time of each borrowing equal to (i) the greater of (a) the prime rate publicly announced by Citibank N.A. or (b) the Federal Funds Effective Rate plus 0.5% or (ii) a Eurodollar rate. Variable interest rates based on either the prime rate or Federal Funds Effective Rate will be increased by an applicable margin ranging from 0% to 0.75%. Variable interest rates based on Eurodollar rates will be increased by an applicable margin ranging from 1% to 1.75%.

 

The $200.0 Million Credit Facility contains various covenants related to Enterprise GP Holdings ability, and the ability of certain of its subsidiaries (excluding Enterprise Products GP and Enterprise Products Partners), to incur certain indebtedness, grant certain liens, make fundamental structural changes, make distributions following an event of default and enter into certain restricted agreements. The credit agreement also requires Enterprise GP Holdings to satisfy certain quarterly financial covenants including (i) its leverage ratio must not exceed 4.5 to 1, except under certain circumstances, and (ii) its minimum net worth must exceed $525.0 million.

 

Enterprise GP Holdings consolidates the debt of Enterprise Products Partners with that of its own; however, Enterprise GP Holdings does not have the obligation to make interest or debt payments with respect to the debt of Enterprise Products Partners.  Enterprise Products Partners is not obligated to pay the debt obligations of Enterprise GP Holdings.

 

Enterprise Products Partners-Subsidiary guarantor relationships

 

Enterprise Products Partners acts as guarantor of the debt obligations of the Operating Partnership, with the exception of the Dixie revolving credit facility and the senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt guaranteed by Enterprise Products Partners, Enterprise Products Partners would be responsible for full repayment of that obligation.

 

The Operating Partnership’s senior indebtedness is structurally subordinated to and ranks junior in right of payment to the indebtedness of GulfTerra and Dixie. This subordination feature exists only to the extent that the repayment of debt incurred by GulfTerra and Dixie is dependent upon the assets and operations of these two entities. The Dixie revolving credit facility is an unsecured obligation of Dixie (of which we own 74.2% of its capital stock). The senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).

 

Operating Partnership debt obligations

 

Multi-Year Revolving Credit Facility. In August 2004, the Operating Partnership entered into a five-year multi-year revolving credit agreement in connection with the completion of the GulfTerra Merger. In October 2005, the borrowing capacity under this credit agreement was increased from $750 million to $1.25 billion, with the possibility that the borrowing capacity could be further increased to $1.4 billion (subject to certain conditions). In June 2006, the Operating Partnership amended the terms of this credit agreement a second time. The second amendment, among other things, extends the maturity date of the Multi-Year Revolving Credit Facility from October 2010 to October 2011 with respect to $1.25 billion of the commitments. Borrowings with respect to $48.0 million in commitments mature in October 2010. The Operating Partnership may make up to two requests for one-year extensions of the maturity date (subject to certain conditions). There is no limit on the amount of standby letters of credit that can be outstanding under the amended facility.

 

The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.

 

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As defined by the credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at (i) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (ii) a Eurodollar rate plus an applicable margin or (iii) a Competitive Bid Rate.

 

This revolving credit agreement contains various covenants related to our ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also requires us to satisfy certain financial covenants at the end of each fiscal quarter. The second amendment modified these financial covenants to, among other things, allow the Operating Partnership to include in the calculation of its Consolidated EBITDA (as defined in the credit agreement) pro forma adjustments for significant capital projects. In addition, the second amendment allows for the issuance of hybrid debt securities, such as the $550.0 million in principal amount of Junior Subordinated Notes A issued by the Operating Partnership during the third quarter of 2006.

 

The Multi-Year Revolving Credit Facility restricts the Operating Partnership’s ability to pay cash distributions to us if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid.

 

In March 2006, Enterprise Products Partners generated net proceeds of $430.0 million in connection with the sale of 18,400,000 of its common units in an underwritten equity offering. In addition, in September 2006, Enterprise Products Partners generated net proceeds of $320.8 million in connection with the sale of 12,650,000 of its common units in an underwritten equity offering. Subsequently, these amounts were contributed to the Operating Partnership, which primarily used such proceeds to temporarily reduce debt outstanding under its Multi-Year Revolving Credit Facility.

 

Pascagoula MBFC Loan. In connection with the construction of our Pascagoula, Mississippi natural gas processing plant in 2000, the Operating Partnership entered into a ten-year fixed-rate loan with the Mississippi Business Finance Corporation (“MBFC”). This loan is subject to a make-whole redemption right and is guaranteed by Enterprise Products Partners through an unsecured and unsubordinated guarantee. The Pascagoula MBFC Loan contains certain covenants including the maintenance of appropriate levels of insurance on the Pascagoula facility.

 

The indenture agreement for this loan contains an acceleration clause whereby if the Operating Partnership’s credit rating by Moody’s declines below Baa3 in combination with Enterprise Products Partners’ credit rating at Standard & Poor’s declining below BBB-, the $54 million principal balance of this loan, together with all accrued and unpaid interest, would become immediately due and payable 120 days following such event. If such an event occurred, Enterprise Products Partners would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support our obligation under this loan.

 

Senior Notes B through K. These fixed-rate notes are unsecured obligations of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. They are senior to any future subordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. Enterprise Products Partners’ guarantee of such notes is non-recourse to Enterprise Products GP.

 

Senior Notes B through D are subject to make-whole redemption rights and were issued under an indenture containing certain covenants. These covenants restrict Enterprise Products Partners’ ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. The remainder of the Senior Notes (E through K) are also subject to similar covenants.

 

Senior Notes E, F, G, and H were issued as private placement debt in September 2004 and generated an aggregate $2 billion in proceeds, which were used to repay amounts borrowed under an acquisition-related credit facility. Senior Notes E through H were exchanged for registered debt securities in March 2005.

 

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Senior Notes I and J were issued as private placement debt in February 2005 and generated an aggregate $500 million in proceeds, which were used to repay $350 million due under a senior note obligation that matured in March 2005 and the remainder for general partnership purposes, including the temporary repayment of amounts then outstanding under the Multi-Year Revolving Credit Facility. Senior Notes I and J were exchanged for registered debt securities in August 2005.

 

Senior Notes K were issued as registered securities in June 2005 and generated $500 million in proceeds, which were used for general partnership purposes, including the temporary repayment of amounts then outstanding under the Multi-Year Revolving Credit Facility. Senior Notes K were issued under the $4 billion universal shelf registration statement Enterprise Products Partners filed in March 2005.

 

Junior Subordinated Notes A. In the third quarter of 2006, the Operating Partnership sold $550.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due 2066 (“Junior Subordinated Notes A”). The Operating Partnership used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. The Operating Partnership’s payment obligations under Junior Subordinated Notes A are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement). Enterprise Products Partners guaranteed the Operating Partnership’s repayment of amounts due under Junior Subordinated Notes A through an unsecured and subordinated guarantee.

 

The indenture agreement governing Junior Subordinated Notes A allows the Operating Partnership to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions. The indenture agreement also provides that, unless (i) all deferred interest on Junior Subordinated Notes A has been paid in full as of the most recent interest payment date, (ii) no event of default under the indenture agreement has occurred and is continuing and (iii) Enterprise Products Partners is not in default of its obligations under related guarantee agreements, neither Enterprise Products Partners nor the Operating Partnership cannot declare or make any distributions to any of its respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or are subordinated to the Junior Subordinated Notes A.

 

The Junior Subordinated Notes A will bear interest at a fixed annual rate of 8.375% from July 2006 to August 2016, payable semi-annually in arrears in February and August of each year, commencing in February 2007. After August 2016, the Junior Subordinated Notes A will bear variable rate interest at an annual rate equal to the 3-month LIBOR rate for the related interest period plus 3.708%, payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to the certain provisions. The Junior Subordinated Notes A mature in August 2066 and are not redeemable by the Operating Partnership prior to August 2016 without payment of a make-whole premium.

 

In connection with the issuance of Junior Subordinated Notes A, the Operating Partnership entered into a Replacement Capital Covenant in favor of the covered debt holders (as defined in the underlying documents) pursuant to which the Operating Partnership agreed for the benefit of such debt holders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the of issuance of certain securities.

 

Dixie Revolving Credit Facility

 

As a result of acquiring a controlling interest in Dixie in February 2005, we began consolidating the financial statements of Dixie with those of our own. In accordance with GAAP, Enterprise Products Partners consolidate the debt of Dixie with that of its own; however, Enterprise Products Partners does not have the obligation to make interest or debt payments with respect to Dixie’s debt. Dixie’s debt obligations consist of a senior unsecured revolving credit facility having a borrowing capacity of $28.0 million. The maturity date of this facility was extended from June 2007 to June 2010 in August 2006.

 

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As defined in the Dixie credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at either (i) a Eurodollar rate plus an applicable margin or (ii) the greater of (a) the Prime Rate or (b) the Federal Funds Rate plus ½%.

 

The credit agreement contains various covenants related to Dixie’s ability to incur certain indebtedness; grant certain liens; enter into merger transactions; and make certain investments. The loan agreement also requires Dixie to satisfy a minimum net worth financial covenant. The revolving credit agreement restricts Dixie’s ability to pay cash dividends to us and its other stockholders if a default or an event of default (as defined in the credit agreement) has occurred and its continuing at the time such dividend is scheduled to be paid.

 

Covenants

 

We are in compliance with the covenants of our consolidated debt agreements at December 31, 2006.

 

Information regarding variable interest rates paid

 

The following table shows the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the year ended December 31, 2006.

 

 

Consolidated debt maturity table

 

The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter.

 

 

In accordance with SFAS 6, long-term and current maturities of debt reflects the classification of such obligations at December 31, 2006. With respect to the $500.0 million in principal due under Senior Notes E in October 2007, the Operating Partnership has the ability to use available credit capacity under its Multi-Year Revolving Credit Facility to fund the repayment of this debt. The preceding table and our Consolidated Balance Sheet at December 31, 2006 reflect this ability to refinance.

 

 

 

 

 

 

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Debt Obligations of Unconsolidated Affiliates

 

We have three unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at December 31, 2006, (ii) total debt of each unconsolidated affiliate at December 31, 2006 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.

 

 

The credit agreements of our unconsolidated affiliates contain various affirmative and negative covenants, including financial covenants. These businesses were in compliance with such covenants at December 31, 2006. The credit agreements of our unconsolidated affiliates restrict their ability to pay cash dividends if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend is scheduled to be paid.

 

The following information summarizes significant terms of the debt obligations of our unconsolidated affiliates at December 31, 2006:

 

Cameron Highway. In December 2005, Cameron Highway issued $415.0 million of private placement, non-recourse senior secured notes due December 2017. The senior secured notes were issued in two series - $365.0 million of Series A notes, which bear interest at a fixed annual rate of 5.86%, and $50.0 million of Series B notes, which charge variable interest based on a Eurodollar rate plus 1%. At December 31, 2006, the variable interest rate charged under the Series B notes was 6.18%.

 

The Series A and B notes are secured by (i) mortgages on and pledges of substantially all of the assets of Cameron Highway, (ii) mortgages on and pledges of certain assets of an indirect wholly-owned subsidiary of ours that serves as the operator of the Cameron Highway Oil Pipeline, (iii) pledges by us and our joint venture partner in Cameron Highway of our respective 50% ownership interests in Cameron Highway, and (iv) letters of credit in an amount of $36.8 million each issued by the Operating Partnership and an affiliate of our joint venture partner. Except for the foregoing, the noteholders do not have any recourse against our assets or any of our subsidiaries under the note purchase agreement.

 

In March 2006, Cameron Highway amended the note purchase agreement governing its Series A and B notes to primarily address the effect of reduced deliveries of crude oil to Cameron Highway resulting from production delays. In general, this amendment modified certain financial covenants in light of production forecasts made by management. Also, the amendment specifies that Cameron Highway cannot make distributions to its partners until the earlier of (i) December 31, 2007 or (ii) the date on which Cameron Highway’s debt service coverage ratios are equal to or greater than 1.5 to 1 for three consecutive fiscal quarters. In order for Cameron Highway to resume paying distributions to its partners, no default or event of default can be present or continuing at the date Cameron Highway desires to start paying such distributions.

 

Poseidon. Poseidon has a $150.0 million revolving credit facility that matures in May 2011. Interest rates charged under this revolving credit facility are variable and depend on the ratio of Poseidon’s total debt to its earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. The variable interest rates charged on this debt at December 31, 2006 were 6.68%.

 

Evangeline. At December 31, 2006, long-term debt for Evangeline consisted of (i) $18.2 million in principal amount of 9.9% fixed-rate Series B senior secured notes due December 2010 and (ii) a $7.5

 

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million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract; and by a debt service reserve requirement. Scheduled principal repayments on the Series B notes are $5.0 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios.

 

Evangeline incurred the subordinated note payable as a result of its acquisition of a contract-based intangible asset in the 1990s. This note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B noteholders are either fully cash secured through debt service accounts or have been completely repaid. Variable rate interest accrues on the subordinated note at a Eurodollar rate plus ½%. The variable interest rates charged on this note at December 31, 2006 were 6.08%. Accrued interest payable related to the subordinated note was $7.9 million at December 31, 2006.

 

Note 13. Minority Interest

 

As presented in our Consolidated Balance Sheet, minority interest represents third-party ownership interests in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party ownership in such amounts presented as minority interest. The following table presents the components of minority interest at December 31, 2006:

 

 

The minority interest attributable to the limited partners of Enterprise GP Holdings consists of common units held by the public and affiliates of EPCO. The minority interest attributable to the limited partners of Enterprise Products Partners consists of common units held by the public and affiliates of EPCO. The minority interest attributable to joint venture partners as of December 31, 2006, is primarily attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub, Dixie and Belle Rose.

 

Note 14. Member’s Equity

 

At December 31, 2006, member’s equity consisted of the capital account of Dan Duncan LLC and accumulated other comprehensive income. Subject to the terms of our limited liability company agreement, we distribute available cash to Dan Duncan LLC within 45 days of the end of each calendar quarter. No distributions have been made to date. The capital account balance of Dan Duncan LLC was nominal at December 31, 2006.

 

 

 

 

 

 

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Accumulated other comprehensive income

 

The following table summarizes transactions affecting our accumulated other comprehensive income since December 31, 2005.

 

Other

 

In October 2006, the Operating Partnership acquired all of the capital stock of an affiliated NGL marketing company located in Canada from EPCO and Dan L. Duncan for $17.7 million in cash. The amount paid for this business (which is under common control with us – see Note 16) exceeded the carrying values of the assets acquired and liabilities assumed by $6.3 million, of which $0.3 million was allocated to us and $6.0 million to minority interest.

 

Note 15. Business Segments

 

We have four reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Offshore Pipelines & Services and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.

 

Our integrated midstream energy asset system (including the midstream energy assets of our equity method investees) provides services to producers and consumers of natural gas, NGLs, crude oil and certain petrochemicals. In general, hydrocarbons enter our asset system in a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an onshore natural gas gathering pipeline, an NGL fractionator, an NGL storage facility, or an NGL transportation or distribution pipeline.

 

Many of our equity investees are included within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines. Other examples include our use of the Promix NGL fractionator to process mixed NGLs extracted by our gas plants. The fractionated NGLs we receive from Promix can then be sold in our NGL marketing activities. Given the integral nature of our equity method investees to our operations, we believe the presentation of earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate.

 

The majority of our plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico and Wyoming. Our natural gas, NGL and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas and Louisiana; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii) certain regions of the central and western United States, including the Rocky Mountains. Our marketing activities are headquartered in Houston, Texas and serve customers in a number of regions of the United States including the Gulf Coast, West Coast and Mid-Continent areas.

 

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Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are assigned to each segment on the basis of each asset’s or investment’s principal operations. The principal reconciling difference between consolidated property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net book carrying value of facilities and other assets that contribute to gross operating margin of that particular segment. Since assets under construction generally do not contribute to segment gross operating margin, such assets are excluded from segment asset totals until they are placed in service. Consolidated intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate.

 

Information by segment, together with reconciliations to our consolidated totals, is presented in the following table:

 

 

Note 16. Related Party Transactions

 

Relationship with EPCO and affiliates

 

We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities:

 

 

Unless noted otherwise, our agreements with EPCO are not the result of arm’s length transactions. As a result, we cannot provide assurance that the terms and provisions of such agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.

 

EPCO is a private company controlled by Dan L. Duncan, who is also a director and Chairman of EPE Holdings and Enterprise Products GP. At December 31, 2006, EPCO beneficially owned 75,240,575 (or 84.7%) of Enterprise GP Holdings outstanding units. In addition, EPCO beneficially owned 146,768,946 (or 33.9%) of Enterprise Products Partners’ common units, including 13,454,498 common units owned by Enterprise GP Holdings. In addition, at December 31, 2006, EPCO and its affiliates owned 86.7% of the limited partner interests of Enterprise GP Holdings and 100% of EPE Holdings. Enterprise GP Holdings owns all of the membership interests of Enterprise Products GP. The principal business activity of Enterprise Products GP is to act as Enterprise Products Partners managing partner. The executive officers and certain of the directors of Enterprise Products GP and EPE Holdings are employees of EPCO.

 

EPE Holdings, Enterprise GP Holdings, Enterprise Products Partners and Enterprise Products GP are separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets

 

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and liabilities that are separate from those of EPCO and its other affiliates. EPCO and its private company subsidiaries depend on the cash distributions they receive from Enterprise GP Holdings, Enterprise Products Partners and other investments to fund their other operations and to meet their debt obligations. EPCO and its affiliates received $306.5 million in cash distributions from us during years ended December 31, 2006.

 

The ownership interests in Enterprise Products Partners that are owned or controlled by Enterprise GP Holdings are pledged as security under Enterprise GP Holdings’ credit facility. In addition, the ownership interests in Enterprise GP Holdings and Enterprise Products Partners that are owned or controlled by EPCO and its affiliates, other than those interests owned by Enterprise GP Holdings, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of a private company affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, Enterprise Products Partners and TEPPCO.

 

We have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products. We also lease office space in various buildings from affiliates of EPCO at rates that approximate market rates. In addition, historically, we entered into transactions with a Canadian affiliate of EPCO for the purchase and sell of NGL products in the normal course of business. These transactions were at market-related prices. We acquired this affiliate in October 2006 and began consolidating its financial statements with those of our own from the date of acquisition.

 

Relationship with Duncan Energy Partners

 

In September 2006, Duncan Energy Partners, a consolidated subsidiary of Enterprise Products Partners, was formed, to acquire, own, and operate a diversified portfolio of midstream energy assets. On February 5, 2007, this subsidiary completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.3 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to Enterprise Products Partners along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of Duncan Energy Partners. Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,351,571 common units beneficially owned by Enterprise Products Partners. Enterprise Products Partners used the cash it received from Duncan Energy Partners to temporarily reduce amounts outstanding under its Operating Partnership’s Multi-Year Revolving Credit Facility.

 

In summary, Enterprise Products Partners contributed 66% of its equity interests in the following subsidiaries to Duncan Energy Partners:

 

 

 

 

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In addition to the 34% direct ownership interest Enterprise Products Partners retained in certain subsidiaries of Duncan Energy Partners, it also owns the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. The Operating Partnership of Enterprise Products Partners directs the business operations of Duncan Energy Partners through its control of the general partner of Duncan Energy Partners.

 

The formation of Duncan Energy Partners had no effect on Enterprise Products Partners’ balance sheet at December 31, 2006. For financial reporting purposes, the balance sheet of Duncan Energy Partners will be consolidated into that of Enterprise Products Partners. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners will reflect the historical carrying basis of Enterprise Products Partners in each of the subsidiaries contributed to Duncan Energy Partners.

 

The public owners of Duncan Energy Partners’ common units will be presented as a noncontrolling interest in Enterprise Products Partners consolidated balance sheet beginning in February 2007. The public owners of Duncan Energy Partners have no direct equity interests in the common units of Enterprise Products Partners as a result of this transaction. The borrowings of Duncan Energy Partners will be presented as part of Enterprise Products Partners’ consolidated debt; however, neither the Enterprise GP Holdings nor Enterprise Products Partners has any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

 

Enterprise Products Partners has significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions:

 

 

 

 

Enterprise Products Partners may contribute other equity interests in its subsidiaries to Duncan Energy Partners in the near term and use the proceeds it receives from Duncan Energy Partners to fund its capital spending program. Enterprise Products Partners has no obligation or commitment to make such contributions to Duncan Energy Partners.

 

Omnibus Agreement. In connection with the initial public offering of common units by Duncan Energy Partners, the Operating Partnership also entered into an Omnibus Agreement with Duncan Energy Partners and certain of its subsidiaries that will govern its relationship with them on the following matters:

 

 

 

 

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Indemnification for Environmental and Related Liabilities. The Operating Partnership also agreed to indemnify Duncan Energy Partners after the closing of its initial public offering against certain environmental and related liabilities arising out of or associated with the operation of the assets before February 5, 2007. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, Duncan Energy Partners is not entitled to indemnification until the aggregate amounts of its claims exceed $250.0 thousand. Liabilities resulting from a change of law after February 5, 2007 are excluded from the environmental indemnity provided by the Operating Partnership.

 

The Operating Partnership will also indemnify Duncan Energy Partners for liabilities related to:

 

 

 

 

Reimbursement for Certain Expenditures. The Operating Partnership has agreed to make additional contributions to Duncan Energy Partners as reimbursement for its 66% share of excess construction costs, if any, above (i) the $28.6 million of estimated capital expenditures to complete planned expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional planned brine production capacity and above-ground storage reservoir projects at Mont Belvieu. We estimate the costs to complete the planned expansion of the DEP South Texas NGL Pipeline System (after the closing of the Duncan Energy Partners’ initial public offering) would be approximately $28.6 million, of which Duncan Energy Partners’ 66% share would be approximately $18.9 million. Duncan Energy Partners retained cash from the proceeds of its initial public offering in an amount equal to 66% of these estimated planned expansion costs. The Operating Partnership will make a capital contribution to South Texas NGL for its 34% share of such planned expansion costs.

 

Relationship with TEPPCO

 

TEPPCO became a related party to us in February 2005 in connection with the acquisition of TEPPCO GP by a private company subsidiary of EPCO.

 

Purchase of Pioneer plan from TEPPCO. In March 2006, we paid TEPPCO $38.2 million for Pioneer natural gas processing plant located in Opal, Wyoming and certain natural gas processing rights related to natural gas production from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. After an in-depth consideration of all relevant factors, this transaction was approved by the Audit and Conflicts Committee of our general partner and the Audit and Conflicts Committee of the general partner of TEPPCO. In addition, each party received a fairness opinion rendered by an independent advisor. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility.

 

Jonah Joint Venture with TEPPCO. In August 2006, we announced a joint venture in which we and TEPPCO will be partners in TEPPCO’s Jonah Gas Gathering Company, or Jonah. Jonah owns the Jonah Gas Gathering System (“the Jonah Gathering System”), located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System gathers and transports natural gas produced from the

 

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Jonah and Pinedale fields to regional natural gas processing plants and major interstate pipelines that deliver natural gas to end-user markets.

 

Prior to entering into the Jonah joint venture, we managed the construction of the Phase V expansion and funded the initial construction costs under a letter of intent we signed in February 2006. In connection with the joint venture arrangement, we and TEPPCO will continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.4 Bcf/d. The Phase V expansion is also expected to significantly reduce system operating pressures, which we anticipate will lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which is expected to increase the system gathering capacity to 2 Bcf/d, is projected to be completed in the first quarter of 2007 at an estimated cost of approximately $302.0 million. The second portion of the expansion is expected to cost approximately $142.0 million and be completed by the end of 2007.

 

We manage the Phase V construction project. TEPPCO is entitled to all distributions from the joint venture until specified milestones are achieved, at which point, we will be entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. After subsequent milestones are achieved, we and TEPPCO will share distributions based on a formula that takes into account the respective capital contributions of the parties, including expenditures by TEPPCO prior to the expansion.

 

Since August 1, 2006, we and TEPPCO equally share in the construction costs of the Phase V expansion. During 2006, TEPPCO reimbursed us $109.4 million, which represents 50% of total Phase V costs incurred through December 31, 2006. We had a receivable of $8.7 million from TEPPCO at December 31, 2006, for Phase V expansion costs.

 

Upon completion of the expansion project and based on the formula in the joint venture partnership agreement, we expect to own an interest in Jonah of approximately 20%, with TEPPCO owning the remaining 80%. At December 31, 2006, we owned an approximate 14.4% interest in Jonah. We will operate the Jonah Gathering System.

 

The Jonah joint venture is governed by a management committee comprised of two representatives approved by us and two appointed by TEPPCO, each with equal voting power. After an in-depth consideration of all relevant factors, this transaction was approved by the Audit and Conflicts Committee of Enterprise Products GP and the Audit and Conflicts Committee of the general partner of TEPPCO. The ACG Committee of Enterprise Products GP received a fairness opinion in connection with this transaction. In Enterprise GP Holdings’ Form 10-Q for the nine months ended September 30, 2006, Enterprise GP Holdings’ mistakenly reported that the Audit and Conflicts Committee of TEPPCO GP had also received a fairness opinion in connection with this transaction; however, they did not. The transaction was reviewed and recommended for approval by the Audit Committee of TEPPCO GP, with assistance from an independent financial advisor.

 

We account for our investment in the Jonah joint venture using the equity method. As a result of entering into the Jonah joint venture, we reclassified $52.1 million expended on this project through July 31, 2006 (representing our 50% share at inception of the joint venture) from Other Assets to Investments in and advances to unconsolidated affiliates on our Consolidated Balance Sheet (see Note 9). The remaining $52.1 million we spent through this date is included in the $109.4 million we billed TEPPCO (see above).

 

We have agreed to indemnify TEPPCO from any and all losses, claims, demands, suits, liabilities, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the Jonah joint venture. A claim for indemnification cannot be filed until the losses suffered by TEPPCO exceed $1.0 million. The maximum potential amount of future payments under the indemnity agreement is limited to $100.0 million. All indemnity payments are net of insurance recoveries that TEPPCO may receive from third-party insurance carriers. We carry insurance coverage that may offset any payments required under the indemnification.

 

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Purchase of Houston-area pipelines from TEPPCO. In October 2006, we purchased certain idle pipeline assets in the Houston, Texas area from TEPPCO for $11.7 million in cash. The acquired pipelines will be modified for natural gas service. The purchase of this asset was in accordance with the Board-approved management authorization policy.

 

Purchase and lease of pipelines for DEP South Texas NGL Pipeline System from TEPPCO. In January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in the Houston area for $8.0 million that is part of the DEP South Texas NGL Pipeline. In addition, we entered into a lease with TEPPCO for a 11-mile interconnecting pipeline located in the Houston area. The primary term of this lease expires in September 2007, and will continue on a month-to-month basis subject to termination by either party upon 60 days notice. This pipeline is being leased by a subsidiary of Duncan Energy Partners in connection with operations on its DEP South Texas NGL Pipeline until construction of a parallel pipeline is completed. These transactions were in accordance with the Board-approved management authorization policy.

 

Relationship with Employee Partnerships

 

EPE Unit I. In connection with Enterprise GP Holdings’ initial public offering in August 2005, EPCO formed EPE Unit I to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in EPE Unit I. EPCO serves as the general partner of EPE Unit I. In connection with the closing of Enterprise GP Holdings’ initial public offering, EPCO Holdings, Inc., a wholly owned subsidiary of EPCO, borrowed $51.0 million under its credit facility and contributed the proceeds to its wholly-owned subsidiary, Duncan Family Interests, Inc. (“Duncan Family Interests”).

 

Subsequently, Duncan Family Interests contributed the $51.0 million to EPE Unit I as a capital contribution and was issued the Class A limited partner interest in EPE Unit I. EPE Unit I used the contributed funds to purchase 1,821,428 units directly from us at the initial public offering price of $28.00 per unit. Certain EPCO employees, including all of Enterprise Products GP’s then current executive officers other than the Chairman, were issued Class B limited partner interests without any capital contribution and admitted as Class B limited partners of EPE Unit I.

 

Unless otherwise agreed to by EPCO, Duncan Family Interests and a majority in interest of the Class B limited partners of EPE Unit I, EPE Unit I will terminate at the earlier of five years following the closing of Enterprise GP Holdings’ initial public offering or a change in control of Enterprise GP Holdings or EPE Holdings. EPE Unit I has the following material terms regarding its quarterly cash distribution to partners:

 

 

 

 

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The Class B limited partner interests in EPE Unit I that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to the fifth anniversary of the closing of Enterprise GP Holdings’ initial public offering, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in EPE Unit I will also lapse upon certain change of control events.

 

Since Enterprise GP Holdings have an indirect interest in Enterprise Products Partners through its ownership of Enterprise Products GP, EPE Unit I, including its Class B limited partners, may derive some benefit from Enterprise Products Partners’ results of operations. Accordingly, a portion of the fair value of these equity awards is allocated to Enterprise Products Partners under the EPCO administrative services agreement as a non-cash expense. EPE Holdings, Enterprise GP Holdings, Enterprise Products GP, Duncan Energy Partners, DEP Holdings and Enterprise Products Partners will not reimburse EPCO, EPE Unit I or any of their affiliates or partners, through the administrative services agreement or otherwise, for any expenses related to EPE Unit I, including the contribution of $51 million to EPE Unit I by Duncan Family Interest or the purchase of Enterprise GP Holdings’ units by EPE Unit I.

 

EPE Unit II. In December 2006, EPE Unit II was formed to serve as an incentive arrangement for an executive officer of Enterprise Products GP. This officer, who is not a participant in EPE Unit I, was granted a profits interest in EPE Unit II. EPCO serves as the general partner of EPE Unit II.

 

Duncan Family Interests contributed $1.5 million to EPE Unit II as a capital contribution and was issued the Class A limited partner interest in EPE Unit II. EPE Unit II used these funds to purchase on the open market 40,725 units of Enterprise GP Holdings on the open market at an average price of $36.91 per unit in December 2006. The officer was issued a Class B limited partner interest in EPE Unit II without any capital contribution. The significant terms of EPE Unit II (e.g. termination provisions, quarterly distributions of cash flow, liquidating distributions, forfeitures, and treatment of sale proceeds) are similar to those for EPE Unit I except that the Class A capital base for Duncan Energy Partners is $1.5 million.

 

EPCO Administrative Services Agreement

 

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”). Enterprise Products Partners and its general partner, EPE Holdings and Enterprise GP Holdings, Duncan Energy Partners and its general partner, and TEPPCO and its general partner, among other affiliates, are parties to the ASA. The significant terms of the ASA are as follows:

 

 

 

 

Under the ASA, EPCO subleases to us (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements. We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to our partnership. At December 31, 2005, the retained leases were for a cogeneration unit and approximately 100 railcars.

 

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Should we decide to exercise the purchase options associated with the retained leases, $2.3 million would be payable in 2008 and $3.1 million in 2016.

 

The ASA also addresses potential conflicts that may arise among Enterprise Products Partners and its general partner, Duncan Energy Partners and its general partner, DEP Holdings, LLC (“DEP Holdings”), EPE Holdings and Enterprise GP Holdings, and the EPCO Group, which includes EPCO and its affiliates (but does not include the aforementioned entities and their controlled affiliates). The administrative services agreement provides, among other things, that:

 

 

 

 

Enterprise GP Holdings will be presumed to desire to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, Enterprise Products GP and DEP Holdings that Enterprise GP Holdings has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by EPE Holdings’ chief executive officer after consultation with and subject to the approval of EPE Holdings’ ACG Committee. If the purchase price is reasonably likely to be less than such threshold amount, EPE Holdings’ chief executive officer may make the determination to decline the acquisition without consulting EPE Holdings’ ACG Committee.

 

In the event that Enterprise GP Holdings abandon the acquisition and so notify the EPCO Group, Enterprise Products GP and DEP Holdings, Enterprise Products Partners will have the second right to pursue such acquisition either for it or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan Energy Partners. In the event that Enterprise Products Partners affirmatively directs the opportunity to Duncan Energy Partners, Duncan Energy Partners may pursue such acquisition. Enterprise Products Partners will be presumed to desire to acquire the equity securities until such time as Enterprise Products GP advises the EPCO Group and DEP Holdings that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition of the equity securities, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing Enterprise Products GP’s chief executive officer and ACG Committee. In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP Holdings, the EPCO Group may pursue the acquisition or offer the opportunity to EPCO Holdings or TEPPCO, TEPPCO GP or their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates.

 

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In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the chief executive officer of Enterprise Products GP after consultation with and subject to the approval of the ACG Committee of Enterprise Products GP. If the purchase price or cost is reasonably likely to be less than such threshold amount, the chief executive officer of Enterprise Products GP may make the determination to decline the business opportunity without consulting Enterprise Products GP’s ACG Committee. In the event that Enterprise Products Partners affirmatively directs the business opportunity to Duncan Energy Partners, Duncan Energy Partners may pursue such business opportunity. In the event that Enterprise Products Partners abandons the business opportunity for itself and for Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP Holdings, Enterprise GP Holdings will have the second right to pursue such business opportunity, and will be presumed to desire to do so, until such time as EPE Holdings has determined to abandon the pursuit of such opportunity in accordance with the procedures described above, and shall have advised the EPCO Group that Enterprise GP Holdings has abandoned the pursuit of such acquisition.

 

In the event that Enterprise GP Holdings abandon the acquisition and so notify the EPCO Group, the EPCO Group may either pursue the business opportunity or offer the business opportunity to EPCO Holdings or TEPPCO, TEPPCO GP and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates.

 

None of the EPCO Group, Enterprise Products GP, Enterprise Products Partners, DEP Holdings, Duncan Energy Partners or its operating partnership, Enterprise GP Holdings or EPE Holdings have any obligation to present business opportunities to TEPPCO, TEPPCO GP or their controlled affiliates. Likewise, TEPPCO, TEPPCO GP and their controlled affiliates have no obligation to present business opportunities to the EPCO Group, Enterprise GP Holdings, DEP Holdings, Duncan Energy Partners or its operating partnership, Enterprise GP Holdings or EPE Holdings.

 

Relationships with Unconsolidated Affiliates

 

Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. See Note 9 for a discussion of this alignment of commercial interests. Since we and our affiliates hold ownership interests in these entities and directly or indirectly benefit from our related party transactions with such entities, they are presented here.

 

The following information summarizes significant related party transactions with our current unconsolidated affiliates:

 

 

 

 

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Review and Approval of Transactions with Related Parties

 

Enterprise GP Holdings’ partnership agreement and ACG Committee charter set forth procedures by which related party transactions and conflicts of interest may be approved or resolved by Enterprise GP Holdings or the ACG Committee. Under Enterprise GP Holdings’ partnership agreement, unless otherwise expressly provided therein, whenever a potential conflict of interest exists or arises between Enterprise GP Holdings or any of its affiliates, on the one hand, and Enterprise Products Partners or its subsidiaries, on the other hand, any resolution or course of action by Enterprise GP Holdings or its affiliates in respect of such conflict of interest is permitted and deemed approved by all of Enterprise GP Holdings’ partners, and will not constitute a breach of Enterprise GP Holdings’ partnership agreement or any agreement contemplated by such agreement, or of any duty stated or implied by law or equity. If the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval (defined as the approval of a majority of the members of the ACG Committee), (ii) approved by a vote of a majority of Enterprise GP Holdings’ units (excluding units owned by EPE Holdings and its affiliates), (iii) on terms no less favorable to Enterprise GP Holdings than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to Enterprise GP Holdings, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to Enterprise GP Holdings).

 

Whenever a particular transaction, arrangement or resolution of a conflict of interest is required under Enterprise GP Holdings’ partnership agreement to be “fair and reasonable” to any person, the fair and reasonable nature of such transaction, arrangement or resolution is considered in the context of all similar or related transactions.

 

Enterprise GP Holdings or its Board of Directors may, in Enterprise GP Holdings’ discretion, request that Enterprise GP Holdings’ ACG Committee review and approve related party transactions. As stated above, transactions and conflicts of interest between Enterprise GP Holdings and its affiliates, on the one hand, and Enterprise Products Partners and its subsidiaries, on the other hand, may also be resolved by Special Approval of the ACG Committee of Enterprise Products Partners in accordance with its partnership agreement and committee charter. The review and approval process of the ACG Committee, including factual matters that may be considered in determining whether a transaction is fair and reasonable, is generally governed by Section 7.9 of Enterprise GP Holdings’ partnership agreement. As discussed below, a transaction that receives the ACG Committee’s approval by a majority of its members (i.e., “Special Approval”) is conclusively deemed not a breach of Enterprise GP Holdings’ partnership agreement or any other duties stated or implied by law or in equity. The processes followed by Enterprise Products Partners’ management in approving or obtaining approval of related party transactions are in accordance with its written management authorization policy, which has been approved by the Board.

 

Under Enterprise Products Partners’ Board-approved management authorization policy, the officers of its general partner have authorization limits for purchases and sales of assets, capital expenditures, commercial and financial transactions and legal agreements that ultimately limit the ability of executives of its general partner to enter into transactions involving capital expenditures in excess of $100 million without Board approval. This policy covers all transactions, including transactions with related parties. For example, under this policy, the chairman may approve capital expenditures or the sale or other disposition of assets up to a $100 million limit. Furthermore, any two of the chief executive officer and senior executives who are directors of its general partner may approve capital expenditures or the sale or other disposition of assets up to a $100 million limit and individually may approve capital expenditures or the sale or other disposition of our assets up to $50 million. These senior executives have also been granted full approval authority for commercial, financial and service contracts.

 

In submitting a matter to the ACG Committee, Enterprise GP Holdings or the Board may charge the ACG Committee with reviewing the transaction and providing the Board with a recommendation, or Enterprise GP Holdings or the Board may delegate to the ACG Committee the power to approve the matter. When so engaged, the charter of the ACG Committee currently provides that, unless the ACG Committee determines otherwise, the ACG Committee shall perform the following functions:

 

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In the normal course of business, our management routinely reviews all other related party transactions, including proposed asset purchases and business combinations and purchases and sales of product. As a matter of course, management reviews the terms and conditions of the proposed transactions, performs appropriate levels of due diligence and assesses the impact of the transaction on Enterprise GP Holdings.

 

The ACG Committee does not separately review transactions covered by our administrative services agreement with EPCO, which was previously approved by the ACG Committee and/or the Board. The administrative services agreement governs numerous day-to-day transactions between us and EPCO and its other affiliates, including the provision by EPCO of administrative and other services to us and our reimbursement of costs for those services.

 

Note 17. Income Taxes

 

Our income taxes relates primarily to federal and state income taxes of Seminole and Dixie, our two largest corporations subject to such income taxes. In addition, with the enactment of the Texas Margin Tax in 2006, we have become a taxable entity in the state of Texas.

 

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2006 are as follows:

 

 

 

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We had net operating loss carryforwards of $19.2 million at December 31, 2006. These losses expire in various years between 2007 and 2026 and are subject to limitations on their utilization. We record a valuation allowance to reduce our deferred tax assets to the amount of future tax benefit that is more likely than not to be realized. The valuation allowance was $3.0 million at December 31, 2006 and primarily relates to our net operating loss carryforwards.

 

On May 18, 2006, the State of Texas enacted House Bill 3 which replaced the existing state franchise tax with a “margin tax”. In general, legal entities that conduct business in Texas are subject to the Texas margin tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.

 

Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period of the law’s enactment. We recorded a net deferred tax liability of $6.6 million due to the enactment of the Texas margin tax.

 

Texas margin tax is effective for returns originally due on or after January 1, 2008. For calendar year end companies, the margin tax would be applied to 2007 activity.

 

Note 18. Commitments and Contingencies

 

Litigation

 

On occasion, we are named as a defendant in litigation relating to our normal business activities, including regulatory and environmental matters. Although we are insured against various business risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activities. We are unaware of any significant litigation, pending or threatened, that could have a significant adverse effect on our financial position, cash flows or results of operations.

 

Several lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing methyl tertiary butyl ether (“MTBE”). In general, such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production facility. It is possible, however, that former MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

 

We acquired additional ownership interests in our Mont Belvieu, Texas octane-additive production facility from affiliates of Devon Energy Corporation (“Devon”), which sold us its 33.3% interest in 2003, and Sunoco, Inc. (“Sun”), which sold us its 33.3% interest in 2004. As a result of these acquisitions, we own 100% of the octane-additive production facility. Devon and Sun have indemnified us for any liabilities (including potential liabilities as described in the preceding paragraph) that are in respect of periods prior to the date we purchased such interests and linked to the period of time they held such interests. There are no dollar limits or deductibles associated with the indemnities we received from Sun and Devon.

 

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO, and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and us or our affiliates.  The complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its

 

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affiliates; (ii) us and certain of our affiliates, including the parent company of our general partner; (iii) EPCO, Inc.; and (iv) Dan L. Duncan. 

 

The complaint alleges, among other things, that the defendants have caused TEPPCO to enter into certain transactions with us or our affiliates that are unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO.  These transactions are alleged to include the joint venture to further expand the Jonah Gathering System entered into by TEPPCO and one of our affiliates in August 2006 and the sale by TEPPCO to one of our affiliates of the Pioneer gas processing plant in March 2006. The complaint seeks (i) rescission of these transactions or an award of rescissory damages with respect thereto; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. We believe this lawsuit is without merit and intend to vigorously defend against it. See Note 16 for additional information regarding our relationship with TEPPCO.

 

On February 13, 2007, the Operating Partnership of Enterprise Products Partners received notice from the U.S. Department of Justice (“DOJ”) that it was the subject of a criminal investigation related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”). The Operating Partnership is the operator of this pipeline. On February 14, 2007, the Operating Partnership received a letter from the Environment and Natural Resources Division (“ENRD”) of the DOJ regarding this incident and a previous release of ammonia on September 27, 2004 from the same pipeline.  The ENRD has indicated that it may pursue civil damages against the Operating Partnership and Magellan as a result of these incidents.  Based on this correspondence from the ENRD, the statutory maximum amount of civil fines that could be assessed against the Operating Partnership and Magellan is up to $17.4 million in the aggregate. The Operating Partnership is cooperating with the DOJ and is hopeful that an expeditious resolution acceptable to all parties will be reached in the near future.  The Operating Partnership is seeking defense and indemnity under the pipeline operating agreement between it and Magellan. At this time, we do not believe that a final resolution of either the criminal investigation by the DOJ or the civil claims by the ENRD will have a material impact on our consolidated results of operations.

 

On October 25, 2006, a rupture in the Magellan Ammonia Pipeline resulted in the release of ammonia near Clay Center, Kansas. We and Magellan are in the process of estimating the repair and remediation costs associated with this release. Environmental remediation efforts continue in and around the site of the release under the supervision and management of affiliates of Magellan. Our operating agreement with Magellan provides the Operating Partnership with an indemnity clause for claims arising from such releases. At this time, we do not believe that this incident will have a material impact on our consolidated results of operations.

 

 

 

 

 

 

 

 

 

 

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Contractual Obligations

 

The following table summarizes our various contractual obligations at December 31, 2006. A description of each type of contractual obligation follows.

 

 

Scheduled Maturities of Long-Term Debt. We have long-term and short-term payment obligations under debt agreements such as the indentures governing the Operating Partnership’s senior notes and the credit agreement governing the Operating Partnership’s Multi-Year Revolving Credit Facility. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the periods indicated. See Note 12 for additional information regarding our consolidated debt obligations.

 

Operating Lease Obligations. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year.

 

Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, and (iii) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 14 to 20 years and include renewal options that could extend the agreements for up to an additional 20 years. Our rental payments under these agreements are generally at fixed rates, as specified in the individual contract, and may be subject to escalation provisions for inflation or other market-determined factors. With regards to our leases of underground storage caverns, we may be assessed contingent rental payments when our storage volumes exceed our reserved capacity.

 

The operating lease commitments shown in the preceding table exclude the non-cash, related party expense associated with equipment leases contributed to us by EPCO at our formation (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements, which it accounts for as operating leases. At December 31, 2006, the retained leases were for a cogeneration unit and approximately 100 railcars. EPCO’s minimum future rental payments under these leases are $2.1 million for each of the years 2007 through 2008, $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016.

 

The retained lease agreements contain lessee purchase options, which are at prices that approximate fair value of the underlying leased assets. EPCO has assigned these purchase options to us. Should we decide to exercise the remaining purchase options, up to an additional $2.3 million would be payable in 2008 and $3.1 million in 2016.

 

Purchase Obligations. We define a purchase obligation as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and

 

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the approximate timing of the transactions. We have classified our unconditional purchase obligations into the following categories:

 

 

 

 

Commitments Under Equity Compensation Plans of EPCO

 

In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us. This includes costs associated with unit option awards granted to these employees to purchase Enterprise Products Partners’ common units. At December 31, 2006, there were 2,416,000 units outstanding for which we were responsible for reimbursing EPCO for the costs of such awards.

 

The weighted-average strike price of unit option awards outstanding at December 31, 2006 was $23.32 per common unit. At December 31, 2006, 591,000 of these unit options were exercisable. An additional 785,000, 450,000 and 590,000 of these unit options will be exercisable in 2008, 2009 and 2010, respectively. As these options are exercised, we will reimburse EPCO in the form of a special cash distribution for the difference between the strike price paid by the employee and the actual purchase price paid for the units awarded to the employee. See Note 4 for additional information regarding our accounting for equity awards.

 

Performance Guaranty

 

In December 2004, a subsidiary of the Operating Partnership entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement, as amended, obligates our subsidiary to construct the Independence Hub offshore platform and to process 1 Bcf/d of natural gas and condensate for the producers.

 

The Operating Partnership has guaranteed to the producers the construction-related performance of its subsidiary up to an amount of $340.8 million. This figure represents the maximum amount the operating partnership would pay to the producers in the remote circumstance where they must finish construction of the platform because its subsidiary failed to do so. This guarantee will remain in place until the earlier of (i) the date all guaranteed obligations terminate or expire, or have been paid or otherwise performed or discharged in full, (ii) upon mutual written consent of the Operating Partnership, the producers and the joint venture partners in the platform project or (iii) mechanical completion of the platform. The Operating Partnership expect that mechanical completion of the Independence Hub platform will occur in March 2007; therefore, it anticipates that the performance guaranty will exist until at least this forecasted date.

 

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In accordance with FIN 45, “Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that our Operating Partnership would be required to perform under the guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of other current liabilities on our Consolidated Balance Sheet at December 31, 2006.

 

Other Claims

 

As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally make claims against such parties or have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of December 31, 2006, our contingent claims against such parties were approximately $2 million and claims against us were approximately $34 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated. However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote. Accordingly, accruals for loss contingencies related to these matters, if any, that might result from the resolution of such disputes have not been reflected in our consolidated financial statements.

 

Other Commitments

 

We transport and store natural gas, NGLs, and certain petrochemicals for third parties under various processing, storage, transportation and similar agreements. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. We are insured against any physical loss of such volumes due to catastrophic events. At December 31, 2006, NGL and petrochemical volumes aggregating 8.5 million barrels were due to be redelivered to their owners along with 12,063 BBtus of natural gas.

 

Note 19. Significant Risks and Uncertainties

 

Nature of Operations in Midstream Energy Industry

 

Our operations are within midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, certain petrochemicals and crude oil. As such, our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products, including changes in the relative price levels among these products. In general, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

 

Our profitability could be impacted by a decline in the volume of hydrocarbon products transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or crude oil refining, for reasons such as depressed commodity prices or a decrease in exploration and development activities, could result in a decline in the volume of natural gas, NGLs and crude oil handled by our facilities.

 

A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made using NGLs, (iii) increased competition from petroleum-based products due to pricing differences, (iv) adverse weather conditions, (v) government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could adversely affect our results of operations, cash flows and financial position.

 

 

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Credit Risk due to Industry Concentrations

 

A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions. We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.

 

Counterparty Risk with respect to Financial Instruments

 

Where we are exposed to credit risk in our financial instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. We generally do not require collateral for our financial instrument transactions.

 

Weather-Related Risks

 

We participate as named insureds in EPCO’s current insurance program, which provides us with property damage, business interruption and other coverages, which are customary for the nature and scope of our operations. EPCO attempts to place all insurance coverage with carriers having ratings of “A” or higher. However, two carriers associated with the EPCO insurance program were downgraded to BBB+ by Standard & Poor’s during 2006. At present, there is no indication that these carriers would be unable to fulfill any insuring obligation. Furthermore, we currently do not have any claims which might be affected by these carriers. EPCO continues to monitor these situations.

 

We believe EPCO maintains adequate insurance coverage on our behalf; however, insurance will not cover every type of interruption that might occur. As a result of severe hurricanes such as Katrina and Rita that occurred in 2005, market conditions for obtaining property damage insurance coverage have been difficult. Under EPCO’s renewed insurance programs, coverage is more restrictive, including increased physical damage and business interruption deductibles. For example, our deductible for onshore physical damage increased from $2.5 million to $5.0 million per event and our deductible period for onshore business interruption claims increased from 30 days to 60 days. Additional restrictions will be applied in connection with damage caused by named windstorms.

 

If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for repair costs or lost income. Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to partners and, accordingly, adversely affect the market price of our common units.

 

The following is a discussion of the general status of our insurance claims related to recent significant storm events. To the extent we include any estimate or range of estimates regarding the dollar value of damages, please be aware that a change in our estimates may occur as additional information becomes available.

 

Hurricane Ivan insurance claims. Our final purchase price allocation related to the merger of GulfTerra with a wholly owned subsidiary of Enterprise Products Partners in September 2004 (the “GulfTerra Merger”) included a $26.2 million receivable for insurance claims related to expenditures to repair property damage to certain pre-merger GulfTerra assets caused by Hurricane Ivan. During 2006, we received cash reimbursements from insurance carriers totaling $24.1 million related to these property damage claims, and we expect to recover the remaining $2.1 million in 2007. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.

 

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In addition, we have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During 2006, we received $17.4 million of nonrefundable cash proceeds from such claims. We are continuing our efforts to collect residual balances and expect to complete the process during 2007. To the extent we receive nonrefundable cash proceeds from business interruption insurance claims, they are recorded as a gain in our Statements of Consolidated Operations in the period of receipt.

 

Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. The majority of repairs to our facilities are completed; however, certain minor repairs are ongoing to two offshore pipelines and an onshore gas processing facility. To the extent that insurance proceeds from property damage claims are not probable of collection or do not cover our estimated expenditures (in excess of $5.0 million of insurance deductibles we expensed during 2005), such amounts are charged to earnings when realized. With respect to these storms, we have $78.2 million of estimated property damage claims outstanding at December 31, 2006, that we believe are probable of collection during the period 2007 through 2009. For the year ended December 31, 2006, we received $10.5 million of physical damage proceeds related to such storms.

 

In addition, we received $46.5 million of nonrefundable cash proceeds from business interruption claims during the year ended December 31, 2006. We are aggressively pursuing collection of our remaining property damage and business interruption claims related to Hurricanes Katrina and Rita.

 

The following table summarizes proceeds we received during 2006 from business interruption and property damage insurance claims with respect to certain named storms:

 

 

 

Note 20. Condensed Financial Information of Operating Partnership

 

The Operating Partnership conducts substantially all of Enterprise Products Partners’ business. Currently, Enterprise Products Partners has no independent operations and no material assets outside those of the Operating Partnership.

 

Enterprise Products Partners guarantees the debt obligations of the Operating Partnership, with the exception of the Dixie revolving credit facility and the senior subordinated notes assumed from GulfTerra. If the Operating Partnership were to default on any debt Enterprise Products Partners guarantees, Enterprise Products Partners would be responsible for full repayment of that obligation. See Note 12 for additional information regarding our consolidated debt obligations.

 

The reconciling items between our consolidated balance sheet and that of the Operating Partnership are insignificant. The most significant reconciling items is that relating to minority interest in our net assets by the limited partner of Enterprise GP Holdings and the elimination of our investments in Enterprise GP Holdings with our underlying partner’s capital account in Enterprise GP Holdings (See Note 1).

 

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The following table presents condensed consolidated balance sheet data for the Operating Partnership at December 31, 2006:

 

 

 

Note 21. Subsequent Events

 

Initial Public Offering of Duncan Energy Partners

 

In September 2006, Duncan Energy Partners, a consolidated subsidiary of Enterprise Products Partners, was formed to acquire, own, and operate a diversified portfolio of midstream energy assets. On February 5, 2007, this subsidiary completed its initial public offering of 14,950,000 common units (including an overallotment of 1,950,000 common units) at $21.00 per unit, which generated net proceeds of $291.3 million. Subsequently, Duncan Energy Partners distributed $260.6 million of these net proceeds to Enterprise Products Partners (along with $198.9 million in borrowings under its credit facility) as consideration for certain equity interests it contributed to Duncan Energy Partners at the closing of its initial public offering. Enterprise Products Partners used the cash received from Duncan Energy Partners to temporarily reduce debt outstanding under the Operating Partnership’s Multi-Year Revolving Credit Facility.

 

Enterprise Products Partners may contribute other equity interests in its subsidiaries to Duncan Energy Partners in the near term and use the proceeds it receives from Duncan Energy Partners to fund its capital spending program.

 

 

Investigation regarding Ammonia Release from Magellan Pipeline

 

On February 13, 2007, the Operating Partnership of Enterprise Products Partners received notice from the U.S. Department of Justice that it was the subject of a criminal and civil investigation related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by Magellan Ammonia Pipeline, L.P. The Operating Partnership is the operator of this pipeline. See Note 18.

 

 

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